· OUR VISION Leading the Way in Electricity SM OUR VALUES Integrity Excellence Respect Continuous Improvement Teamwork OUR SHARED ENTERPRISE Together we prov

2008 ANNUAL REPORT

Leading the Way in ElectricitySM

OUR VISION

Leading the Way in Electricity SM

OUR VALUES

n Integrity n Excellencen Respectn Continuous Improvementn Teamwork

OUR SHARED ENTERPRISE

n Together we provide an indispensable service that powers society.

n We are a single enterprise that is stronger than the sum of its parts.

OUR OPERATING PRIORITIES

n We operate safelyn We meet customer needsn We value diversityn We build productive partnershipsn We protect the environmentn We learn from experience and improven We grow the value of our business

On the cover:(top) SCE linemen at work in Villa Park, California (bottom) EMG’s 19-megawatt wind project in Spanish Fork, Utah

PAGE 1 EDISON INTERNATIONAL 2008 ANNUAL REPORT

FINANCIAL HIGHLIGHTSDollar amounts in millions, except per share data

Year ended December 31, 2008 2007 2006

Operating revenues $14,112 $12,868 $12,169

Operating income $2,563 $2,509 $2,489

Basic earnings per share from continuing operations $3.69 $3.34 $3.28

Dividends paid per common share $1.22 $1.16 $1.08

Total assets at December 31 $44,615 $37,523 $36,261

Return on equity 13.7% 13.6% 16.5%

BUSINESS HIGHLIGHTS

Southern California Edison

System rate base $12,439 $11,719 $10,836

Capital expenditures $2,267 $2,286 $2,226

Peak demand (megawatts) 22,020 23,303 22,889

Total system sales (kilowatt-hours, in millions) 98,577 97,688 96,146

Energy efficiency savings (kilowatt-hours, in millions) 1,691 1,635 792

Employees 16,344 15,442 14,362

Edison Mission Group

Generation capacity at December 31 (megawatts) 9,849 9,453 9,303

Wind generation (megawatts)

(in operation and under construction at December 31) 1,185 1,013 616

Capital expenditures $556 $540 $310

Employees 1,889 1,793 1,751


Superior execution.Financial discipline.Innovative approaches.

Edison International has been tested before by tough andunpredictable financial times. We endured, and ultimatelygrew stronger. We are facing the present economic challenges with the seriousness, and the confidence, thatcomes from experience.

State and national policy objectives for cleaner generation,grid reliability, and advanced energy technologies continueto offer attractive growth opportunities for EdisonInternational. We commit ourselves to the superior execution of our daily operations and our plans forgrowth. We focus on good financial discipline, so that wecan operate from a position of strength as opportunitiesand challenges arise. And our innovative approaches toadvanced technology and environmental stewardshiphave earned us valuable leadership positions in a numberof key areas.

We are optimistic that adhering to these fundamentalsshould enable us to realize our substantial growth potential and build long-term value for customers,shareholders and employees.


Edison International in 2008 largely achieved theperformance goals we set for ourselves at the begin-ning of the year, and net income grew 11 percent toa record $1.22 billion, or $3.69 per share.

Based solely on these measures, we would consider2008 to be a good, solid year of performance. But of course it was not a normal year, for EdisonInternational or for the economy as a whole. Ouraccomplishments must be viewed in the context ofthe dramatic decline in the economy and the stockmarket. Our stock price fell 39.8 percent in 2008,generally in line with the 38.5 percent decline ofthe S&P 500.

Our peers, measured by the Philadelphia UtilityIndex, performed somewhat better as a group, witha decline of 29.9 percent for the year. This indexconsists of “pure-play” utilities, where essentiallythe entire business is regulated, and “integrated”utilities like Edison International. We operate botha regulated utility, Southern California Edison(SCE), and a competitive generation business,Edison Mission Group (EMG). In 2008 our stockperformed somewhat worse than the pure-play utilities, which were viewed as more insulated fromthe economic turmoil, but better than the purecompetitive generation businesses, which wereimpacted greatly.

In this, my first letter to shareholders as chairmanand CEO of your company, I want to share what Ibelieve underlies the value creation opportunity atEdison International. We have a strong foundation,and we are in a good position to achieve our sub-stantial growth objectives – but it will requiresuperior execution, financial discipline and innova-tive approaches to our business.

THE FOUNDATIONS OF OUR VALUE

Neither the global financial crisis nor the weakenedeconomy has altered the four most significant drivers

of Edison International’s growth potential, which webelieve is among the best in our industry.

1. Investments in renewable energy, grid reliability,and advanced energy technologies are importantpublic policy objectives at the national, state andlocal levels. Investment to meet these objectivesforms the core of our growth strategy at bothSCE and EMG.

2. We have the scale and stability of one of thelargest electric utilities in the country, coupledwith the upside opportunity of our competitivegeneration business and its strategic flexibilityto participate in multiple markets.

3. We have a strong financial position. Our total liquidity at year-end was in excess of $5.5 billion, we have no significant long-termdebt maturities until 2012, and we generatestrong cash flow from operations.

4. We have skilled and committed employees, ledby able and seasoned management, focused onoperating safely and serving our customers andthe communities in which we do business.

SUPERIOR EXECUTION OF OUR

GROWTH PROGRAMS

Our ability to realize Edison International’s growthpotential rests principally on how we execute twoinitiatives: a five-year, $21 billion capital investmentplan at SCE, the largest such program in our history;and the development of a large renewable energyproject pipeline at EMG consisting of approximately5,000 megawatts of potential wind and solar energyprojects. Successful execution of these plans wouldbenefit electricity customers and the environment,and dramatically grow the earning assets of the company over the next few years.

Fellow Shareholders:


These investment and development programs consti-tute a large, diverse and extremely complex volumeof work. They demand superior execution on manyfronts including planning, permitting, engineering,procurement and construction management.

The SCE capital investment program. SCE hasincreased its infrastructure investment significantlyover the last three years, and 2009 will be particu-larly important as the company ramps up to aneven greater level. Projects totaling as much as$3.6 billion are planned in five main areas:

n Reliability investments in the distribution system;

n Transmission investments, particularly to enablethe development of new sources of renewableenergy;

n Edison SmartConnectTM, our advanced meter program;

n Replacement of steam generators to extend thelife of our San Onofre Nuclear GeneratingStation; and,

n Our proposal to launch an innovative solar initiative using the rooftops of large commercial buildings.

In addition to the challenges associated with com-pleting these large capital projects, there is anotherconcern: the financial impact on SCE customers.The accelerated pace of investment in reliabilityand in a smarter, cleaner, electricity system will putupward pressure on SCE customer rates in 2009and beyond, an issue to which we are acutely sensi-tive given the weakened economy. Declining fuelcosts will partially offset rate changes in the nearterm, but we are taking action on multiple fronts tohelp our customers.

As always, we are aggressively promoting ourenergy-efficiency and demand-response programs tohelp SCE customers lower their monthly electricitybills. We offer extended payment arrangements tocustomers experiencing difficulty paying their bills,and rate reduction programs to income-qualified customers. For customers struggling most, we offerdirect financial assistance through the EnergyAssistance Fund.

REPLACEMENT STEAM GENERATOR EN ROUTE TO SAN ONOFRE


We are also working with legislative leaders, public officials and consumer groups to address an inequity in electricity rates that was createdunintentionally by the state legislature during theCalifornia energy crisis. Today, approximately 50 percent of SCE’s residential customers shoulder100 percent of most new costs. Reform wouldenable the California Public Utilities Commissionto distribute costs fairly while maintaining existingprotections for low-income customers.

EMG renewable energy and natural gas-fired generation development. At EMG, the core of our growth plan is the continued expansion of our wind portfolio. We made good progress in2008, increasing our installed wind capacity by 70 percent. At year-end we had projects in ninestates, with 962 megawatts in service and 223megawatts under construction.

Our wind development pipeline consists ofapproximately 5,000 megawatts of potential projects in 13 states. As we identify projects todevelop that meet our return criteria, our chal-lenge is to drive them to completion through thepermitting, grid interconnection, construction

and financing required to bring a new wind farmon-line. This also will demand superior execution,repeated consistently across multiple projects inseveral states.

The wind development program will for the foreseeable future remain the anchor of our renewables business at EMG, but in 2008 we alsoadvanced our solar program significantly. We areexploring more than 30 sites in six Western statesfor potential solar projects. These generally arelarge-scale projects of 20 to 100 megawatts persite. We are processing interconnection requests,taking steps to secure land rights, and competingfor long-term power sale contracts to utilities.Significantly, we signed a strategic developmentagreement with a photovoltaic solar panel manu-facturer, First Solar Electric, LLC, to develop largesolar utility projects in certain markets.

In addition to EMG’s developments in renewableenergy, we are also exploring opportunities todiversify our portfolio with gas-fired generation. A major potential advance occurred in 2008 when the company was awarded a 10-year,

TRANSMISSION LINE MAINTENANCE

RANCHO VISTA SUBSTATION, SOUTHERN CALIFORNIA


competitively bid power sales agreement withSCE for the output of the Walnut Creek project, a500-megawatt gas-fired plant in the Los Angelesbasin. Although uncertainties about adequate availability of emissions offsets caused us to writeoff some early stage project costs, we are activelypursuing these offsets and remain committed tothis $600 million project.

MAINTAINING GOOD FINANCIAL DISCIPLINE

Our growth programs require large amounts of capital. It is essential that we maintain financialdiscipline in order to give investors the confidenceto fund our projects. Financial strength is a competitive advantage we want to protect and extend.

Our short-term response to the financial crisis has been to follow our natural inclination to manage financial risks on the conservative side. InSeptember, we took the precaution of drawing fromour lines of credit approximately $2.1 billion, eventhough we had no immediate need for the funds. If a long line started to form at the banks, we wantedto have already been there.

We further enhanced our liquidity and tested the bond market in mid-October at SCE with a$500 million, 5.75 percent coupon offering, which

was well received.We were among only a handful of companies able to raise meaningful funds duringthis period.

EMG has been building liquidity and extendingdebt maturities over the last two years with severalhighly favorable opportunistic financings. We didthis to meet our significant growth investments andother obligations even if credit markets tightened.These efforts have provided the significant cashneeded through summer 2009 to complete windpower projects in development. As long as creditmarkets remain difficult, the availability of projectfinancing will be an important factor in any decisionto commit to new construction projects beyondthose currently planned.

For companies that remain strong and stable, thepresent environment may actually create opportuni-ties. The difficulty and increased expense of obtain-ing investment capital, for example, only intensifiesthe challenge of building new power plants. Thatmay ultimately increase the value of existing capac-ity and make the need for new generation all themore urgent in an economic recovery, rewardingthose who are in position to move quickly. We aimto maintain the financial strength and flexibility topursue these opportunities.

MOUNTAIN WIND PROJECT, WYOMING


INNOVATIVE APPROACHES FOR A

LOW-CARBON ECONOMY

Meeting society’s demands for a cleaner, morerobust electricity system will require fundamentalchanges to the way electricity is generated, trans-ported and distributed to customers. Transitions of this magnitude require insightful public policy,precise planning and huge sums of new capital. Italso requires sufficient time for customers, workersand companies to digest the significant costs with-out further weakening the economy.

The transformation of the electricity industryrequires Edison International to change as well. Inmany respects, we are well ahead of the curve; inother areas, we have much work to do.

At SCE, approximately 40 percent of our generationalready comes from low-carbon sources. Innovativeapproaches to renewable energy, energy efficiency,smart grid technology and electric transportationhave made us an industry leader in these areas. This expertise will be increasingly important in the transition to a low-carbon economy, and couldbecome a strong competitive advantage.

Significant effort and capital will be required forSCE to achieve potentially higher state-level goals

for renewable energy. California’s goal for the state’sinvestor-owned utilities is for 20 percent of our customers’ energy needs to come from renewablesources by 2010, and there is growing support toraise that goal to 33 percent by 2020. SCE currentlyleads the nation with a renewables portfolio ofnearly 13 billion kilowatt-hours, representingabout 16 percent of our customers’ energy needs.And yet with load growth, this portfolio will needto more than double in size to meet the higher goal, and significant new transmission will need to be constructed.

At EMG, we have been transitioning our investmentemphasis to the development of wind and solargeneration. The growth of our renewables businessboth furthers, and is supported by, national goals forincreased low-carbon generation.

With respect to our large fleet of merchant coal-fired generation at EMG, the future is morecomplicated and involves more risk. Approximatelythree-quarters of EMG’s generation capacity is coal-fired. Coal is an abundant domestic resource,valuable for energy security in an uncertain world,and has provided low-cost, reliable electricity to

SOLAR ROOFTOP INSTALLATION, FONTANA, CALIFORNIA


customers for decades. One half of the nation’s electricity is produced by coal-fired plants.However, in addition to concerns about the tradi-tional pollutants emitted when coal is burned, coalis also the most carbon intensive of the fuels usedfor generating electricity. It is the center of atten-tion for our industry in the effort to move to a low-carbon economy.

Over the last decade, EMG has invested hundredsof millions of dollars in our coal plants to reduceemissions of mercury, nitrogen oxide, and sulfurdioxide. Some of these efforts have been leading-edge, such as the controls installed last year at threeof our Illinois plants that have dramatically reducedmercury emissions. To achieve the further emissionsreductions required under state and federal regula-tion, EMG will need either to invest billions of dollars in control equipment and emissions credits,retire the plants, or do some combination of both.

At the same time that EMG has been reducing thetraditional pollutants from its coal plants, it hasbeen working on innovative approaches to lower itscarbon intensity. For example, EMG is testing bio-fuels such as switch grass and miscanthus thatmight replace some of its coal burn. Also, EMG’sPowerton plant in Illinois is one of five sites

selected by the Electric Power Research Institute tohost research on advanced control technologies forcapturing carbon emissions at an existing plant.

Achieving these environmental objectives whilecontinuing to invest heavily in the growth ofEMG’s renewables business will require significantcapital. Importantly, EMG pays no regular dividendsto Edison International for the benefit of sharehold-ers. Instead, it reinvests all profits to fund environ-mental controls and grow its low-carbon wind andsolar generation portfolio. And EMG only makes aprofit if it can first recover its costs through marketprices in competitive electricity markets. EMG’slow-cost coal fleet has generated substantial cashflow over the last few years, which has allowed it tomake these investments. That cash flow has provento be volatile and is typically weak during periodsof low commodity prices, such as those experiencedin the early part of this decade and currently. Weare highly focused on ensuring we recover theinvestments already made, and require any newinvestments to have a reasonable prospect of providing investors with capital recovery and anadequate return on investment.

WAUKEGAN GENERATING STATION, ILLINOIS

CONTINUOUS MERCURY MONITOR


TRANSITIONS

In 2008 we said farewell to three leaders who madesignificant contributions to the company’s success.John Bryson retired from the company at the end of July after serving as Edison International’schairman and CEO for 18 years. Chief FinancialOfficer and long-time colleague Tom McDanielalso retired at the end of July, as did GeneralCounsel Lon Bouknight. They contributed greatlyto a substantial growth in the value of the company.

I would also like to thank and recognize BobSmith, who retired as a member of the Board ofDirectors in April after 20 years of service to thecompany. Bob provided leadership and steadinessduring times of great change and challenge. He will be missed.

OUR COMMITMENT

Thank you for your support throughout this pastyear. Our goal is to provide you with superiorresults regardless of the economic climate. I haveattempted in this letter to outline the opportunitiesthat excite us and give us optimism, as well as the challenges we need to overcome. We are deeply

committed to the complex job of building value forall those who count on us to perform: our customers,our shareholders, our employees and our communities.

Over the last few months I have spent a great dealof time in the field touring our operations and talk-ing with employees. These visits have given me aneven greater appreciation for their skill, and pridein their dedication. The men and women of EdisonInternational inspire confidence for the future of our company and are eager to take on the work thatlies ahead.

KERN RIVER COGENERATION PLANT, CALIFORNIA

Theodore F. Craver, Jr.

Chairman, President and Chief Executive Officer

March 2, 2009


Rancho Vista Substation

Construction of SCE’s state-of-the-

art 500kV Rancho Vista Substation,

located in Rancho Cucamonga,

California, will be completed in

mid-2009. This $206 million project

incorporates the latest gas-insulated

substation technology, and features

solar photovoltaic panels on the

rooftop to help provide station

power. This project will improve

system reliability and handle load

growth in the busy Inland Empire

region. The company is expanding

and renewing the region’s essential

distribution and transmission infra-

structure, making the power grid

greener and smarter for 13 million

Southern Californians.

Replacing steam generators atSan Onofre Nuclear GeneratingStation to ensure the continuedoperation of California’s largestsource of low-carbon electricitygeneration.

Renewables

Natural Gas

Hydro

Investing in a reliable,safe neighborhood-levelelectricity distributionsystem that is cleaner,smarter and more efficient.

Installing 5.3 million advanced EdisonSmartConnectTM electricity meters toenhance services for customers andhelp them manage energy use wisely.

Expanding the transmission systemto maintain reliability and increaseaccess to areas rich with potentialfor wind, solar and other renewablepower generation.

Major Elements of SCE’s Five-Year Capital Investment Plan

Approximately 40% ofSCE’s generation comesfrom low-carbon sources.


Buffalo Bear Wind Project

EMG’s Buffalo Bear wind project in

Oklahoma began commercial operation in

late 2008. Buffalo Bear can generate up to

19 megawatts of electricity and is located

near EMG’s 95-megawatt Sleeping Bear

wind project, which began commercial

operation in 2007. Sleeping Bear sells its

power to Public Service Power Company

of Oklahoma, while Buffalo Bear sells its

power under a long-term contract with

Western Farmers Electric Cooperative.

The projects can produce enough electric-

ity to meet the needs of approximately

30,000 homes.

es Edison Mission Group Wind Portfolio

Total Operating 962

Total Construction 223

1,185

Total Pipeline 4,994

MW680 MW

Arizona

141 MWWyoming

19 MWUtah

114 MW430 MW

Oklahoma

825 MWNevada

90 MW100 MW1000 MW

New Mexico

241 MW70 MW400 MW

Texas

145 MW220 MW

Iowa

145 MW165 MW

Minnesota

53 MW282 MW

Nebraska

520 MWIllinois

60 MW

Maryland

195 MWNewYork

117 MWWestVirginia

67 MWPennsylvania

100 MWWisconsin

(as of December 31, 2008)


SOLAR ROOFTOP PROGRAM

This proposed $875 million initiative would place250 megawatts of solar generation on 65 millionsquare feet of unused Southern California commer-cial rooftops. The project was prompted by recentadvances in solar technology that reduce the cost ofinstalled photovoltaic generation.When combinedwith the size of SCE’s investment, the resultingcosts per unit are projected to be half that of com-mon photovoltaic installations in California. SCEcompleted the first of 150 proposed installations inlate 2008 with the placement of 33,700 advancedthin-film solar panels on a 600,000-square-footwarehouse roof in Fontana, California, creating thelargest single rooftop solar photovoltaic array in thestate. A final California Public Utilities Commissiondecision is expected in spring 2009.

STEAM GENERATOR REPLACEMENT

At SCE’s San Onofre Nuclear Generating Station,the largest construction project since the two oper-ating units were built in the 1980s is under way.The plant recently took delivery of the first two offour new 640-ton, 65-foot steam generators thatwill replace components nearing the end of theirservice. This investment in the utility’s largest

asset means the plant can serve out its initial licenseperiod, which runs until 2022, and beyond iflicense renewal proves feasible. The continued operation of Southern California’s largest source ofreliable, low-carbon generation through 2022 alsomeans that customers will save as much as $1 bil-lion when compared to replacement power costs.

EDISON SMARTCONNECT

The California Public Utilities Commission in2008 approved $1.63 billion for SCE’s award-win-ning advanced metering program, known as EdisonSmartConnect. SCE plans to install 5.3 millionsmart meters beginning in 2009, providing resi-dential and small-business customers with greatlyimproved tools and services to help them manageenergy use wisely. The resulting sustained energyconservation could reduce overall peak power consumption by an estimated 1,000 megawatts –the output of a major power plant.

ADVANCED MERCURY EMISSIONS CONTROLS

EMG in 2006 signed a ground-breaking agreementwith the Illinois Environmental Protection Agency

Artificial Kelp Reef

SCE completed construction in 2008 of a

175-acre artificial giant kelp reef off the

coast near the company’s San Onofre

Nuclear Generating Station. SCE built

the reef, the largest environmental pro-

ject of its kind in the United States, to

mitigate impacts from the plant’s use of

ocean water for cooling. Kelp is the

marine equivalent of a rainforest. It allows

sea life to survive, providing food, shelter,

camouflage and an environment for

spawning. The reef includes the place-

ment of 120,000 tons of rock on the

ocean floor and is expected to produce

the nation’s first sustainable artificial kelp

forest, attracting many species of coastal

fish and invertebrates that depend on

such underwater habitats for shelter

and food.


related to the six coal-fired plants the companyoperates in that state. As part of the agreement,EMG completed mercury emission control instal-lations in 2008 at its Waukegan plant and atCrawford and Fisk stations in Chicago. These sitesare consistently achieving in the range of 80 per-cent removal of mercury emissions since EMGbegan using activated carbon injection (ACI) toremove mercury from the coal combustion process.The construction of the ACI systems on the balanceof the fleet will be completed by the summer of2009. EMG pioneered the use of ACI and wasamong a small number of companies that did earlyfield-testing of the process through a grant fromthe U.S. Department of Energy in 2006 and 2007.

ENERGY EFFICIENCY

For more than 25 years, SCE has offered its customersaward-winning energy-efficiency programs to helpthem save energy, reduce their electricity bills, andhelp the environment. From 2006 to 2008, SCEhad the highest goals in the nation for energy-efficiency savings – and beat them. For the three-year program cycle, SCE helped customers achieve

more than 4 billion kilowatt-hours of energy savings and 713 megawatts of demand reduction.For the upcoming 2009 to 2011 program cycle,SCE once again has the highest energy savings goalsin the nation: 3.5 billion kilowatt-hours of savingsand 741 megawatts of demand reduction.

SAFETY CULTURE

Edison International made progress strengtheningthe company’s safety culture in 2008, workingtoward the goal of an injury-free workplace. Thefindings of a safety culture survey conducted in2007 were used by business units across the company to implement tailored safety initiatives.The company achieved a reduction in OSHA-recordable injuries over the previous year. Thisincluded standout performance at EMG’s Crawfordand Will County stations, which earned theOutstanding Safety and Health Performance Awardfrom the Illinois Safety Council in 2008. The awardis based on year-over-year improvements in record-able accidents and days lost from work due to

Electric Transportation

SCE’s Electric Vehicle Technical Center in

Pomona, California – unique in the utility

industry – provides a broad range of electric

transportation services, focusing on solutions

for automakers, battery manufacturers,

government agencies, and business and

industrial fleet customers. In 2008, more than

400 national and international public officials,

as well as executives from the automobile

and utility industries, visited the technical

center. Also in 2008, SCE and Ford Motor

Company expanded their industry-leading

evaluation of plug-in hybrid prototypes to

include the U.S. Department of Energy, the

Electric Power Research Institute, and several

major U.S. utilities. In addition, SCE formed a

new partnership with Mitsubishi Motors to

evaluate and demonstrate the market potential

of its new iMiEV electric vehicle.


injury. The company’s progress to date, combinedwith a continued focus on underlying culturalissues, position Edison International well for con-tinued safety performance improvements in 2009and beyond.

ETHICS AND COMPLIANCE

Edison International continues to further strengthenits ethics and compliance programs. The company’sefforts include a substantial emphasis on ethics train-ing for all employees. In 2008, executives, man-agers and supervisors received additional trainingthat stressed the key role leaders must play in rein-forcing a healthy ethics culture. During the year, allnon-union employees completed the annual ethicsand compliance certification process. This processrequires employees to take personal accountabilityby self-reporting issues that may not comply withthe Ethics and Compliance Code. Employees alsohave around-the-clock access to the Ethics Helplineto raise and identify issues and concerns or obtainadvice. In 2008, the company also introduced the

“When to Question/When to Support” communi-cations campaign encouraging employees to speakup when they see a problem or an opportunity toimprove performance.

LIVING OUR VALUES

In 2008, Edison International strengthened itshigh-performance culture through a comprehensivevalues education and employee engagement effortaround the core values of Integrity, Excellence,Respect, Continuous Improvement and Teamwork.The program culminated in the Chairman’s Award,a company-wide recognition program that celebratesthe work of 40 extraordinary employees and theircontributions to the company. The work has helpeddrive greater levels of awareness, understanding andcommitment across the organization. Survey resultsin 2008 indicate that employees recognize theimportance of values-based performance.

Serving OurCommunities

Employees at EMG’s Powerton Stationvolunteered their time in 2008 torebuild the home of an elderly womanin Peoria, Illinois, identified by a non-profit agency in the area.More than 50 station employees and their familiesworked evenings and weekends over a three-month period,building newplumbing, rewiring the house, repairingsiding and windows, replacing floors,installing a new thermostat, paintingand more. In 2008,Edison Internationalemployees, retirees and their familiesvolunteered 227,000 hours in theircommunities. The company gave $12.8 million in shareholder-fundedcontributions,while employees donated nearly $3.9 million of their own money.

Theodore F. Craver, Jr.3

Chairman of the Board, President and Chief Executive Officer,Edison InternationalA director since 2007

Vanessa C.L. Chang1,4

Principal, EL & EL Investments(private real estate investment company)Los Angeles, CaliforniaA director since 2007

France A. Córdova4,5

President, Purdue UniversityWest Lafayette, IndianaA director since 2004

Charles B. Curtis4,5

President and Chief Operating Officer,Nuclear Threat Initiative (private foundation dealing withnational security issues)Washington, DCA director since 2006

Bradford M. Freeman1,2,3

Founding Partner,Freeman Spogli & Co.(private investment company)Los Angeles, CaliforniaA director since 2002

Luis G. Nogales1,4

Managing Partner,Nogales Investors, LLC(private equity investment company)Los Angeles, CaliforniaA director since 1993

Ronald L. Olson3,4

Senior Partner,Munger, Tolles & Olson (law firm)Los Angeles, CaliforniaA director since 1995

James M. Rosser2,3,5

President,California State University, Los AngelesLos Angeles, CaliforniaA director since 1988

Richard T. Schlosberg, III1,2,5

Retired President and Chief Executive Officer,The David and Lucile Packard Foundation(private family foundation)San Antonio, TexasA director since 2002

Thomas C. Sutton1,2,3

Retired Chairman of the Board andChief Executive Officer,Pacific Life Insurance CompanyNewport Beach, CaliforniaA director since 1995

Brett White2,5

President and Chief Executive Officer,CB Richard Ellis(commercial real estate services company)A director since 2007

1 Audit Committee2 Compensation and Executive

Personnel Committee3 Executive Committee4 Finance Committee5 Nominating/Corporate Governance

Committee

Theodore F. Craver, Jr.Chairman of the Board,President and Chief Executive Officer

Robert L. AdlerExecutive Vice President and General Counsel

Polly L. GaultExecutive Vice President,Public Affairs

W. James ScilacciExecutive Vice President,Chief Financial Officer and Treasurer

Diane L. FeatherstoneSenior Vice President,Human Resources

Barbara J. ParskySenior Vice President,Corporate Communications

Jeffrey L. BarnettVice President,Tax

Scott S. CunninghamVice President,Investor Relations

Andrew J. HertnekyVice President,Strategic Planning

Barbara E. MathewsVice President, Associate General Counsel, Chief Governance Officer andCorporate Secretary

Megan Scott-KakuresVice President and General Auditor

Kenneth S. StewartVice President and Chief Ethics and Compliance Officer

Linda G. SullivanVice President and Controller

Board of Directors Edison International

Southern California Edison Company

Alan J. FohrerChairman of the Board and Chief Executive Officer

John R. FielderPresident

Pedro J. PizarroExecutive Vice President,Power Operations

Bruce C. FosterSenior Vice President,Regulatory Affairs

Cecil R. HouseSenior Vice President,Safety, Operations Support and Chief Procurement Officer

James A. KellySenior Vice President,Transmission and Distribution

Thomas M. NoonanSenior Vice President and Chief Financial Officer

Stephen E. PickettSenior Vice President and General Counsel

Ross T. RidenoureSenior Vice President and Chief Nuclear Officer

Mahvash YazdiSenior Vice President,Business Integration and Chief Information Officer

Lynda L. ZieglerSenior Vice President,Customer Service

Robert C. BoadaVice President and Treasurer

Lisa D. CagnolattiVice President,Business Customer Division

Kevin R. CiniVice President,Energy Supply and Management

Ann P. CohnVice President and Associate General Counsel

Paul J. De MartiniVice President,Advanced Technology

Erwin G. FurukawaVice President,Customer Programs and Services

Stuart R. HemphillVice President,Renewable and Alternative Power

Harry B. HutchisonVice President,Customer Service Operations

Akbar JazayeriVice President,Regulatory Operations

Walter J. JohnstonVice President,Power Delivery

R. W. (Russ) Krieger, Jr.Vice President,Power Production

Barbara E. MathewsVice President, Associate General Counsel, Chief Governance Officer andCorporate Secretary

David L. MeadVice President,Engineering and Technical Services

Kevin M. PayneVice President,Enterprise Resource Planning

Frank J. QuevedoVice President,Equal Opportunity

Megan Scott-KakuresVice President and General Auditor

Michael P. ShortVice President,Nuclear Engineering and Technical Services

Leslie E. StarckVice President,Local Public Affairs

Kenneth S. StewartVice President and Chief Ethics and Compliance Officer

Linda G. SullivanVice President and Controller

Edison Mission Group*

Ronald L. LitzingerChairman of the Board, President and Chief Executive Officer

John P. Finneran, Jr.Senior Vice President and Chief Financial Officer

Steven D. EisenbergSenior Vice President and General Counsel

Guy F. GorneySenior Vice President,Generation

Paul JacobSenior Vice President,Marketing and Trading

Gerard P. LoughmanSenior Vice President,Development

Douglas R. McFarlanSenior Vice President,Public Affairs and Communications

Jenene J. WilsonVice President,Human Resources

*Parent company of Edison Mission Energy and Edison Capital

Annual Meeting

The annual meeting of shareholders

will be held on Thursday, April 23,

2009, at 9:00 a.m., Pacific Time, at

the Hilton Los Angeles San Gabriel

Hotel, 225 West Valley Boulevard,

San Gabriel, California 91776.

Corporate Governance Practices

A description of Edison

International’s corporate governance

practices is available on our Web

site at www.edisoninvestor.com.

The Edison International Board

Nominating/ Corporate Governance

Committee periodically reviews the

Company’s corporate governance

practices and makes recommenda-

tions to the Company’s Board

that the practices be updated from

time to time.

Stock Listing and TradingInformational Common Stock

The New York Stock Exchange

uses the ticker symbol EIX; daily

newspapers list the stock as

EdisonInt.

Transfer Agent and Registrar

Wells Fargo Bank, N.A., which

maintains shareholder records, is

the transfer agent and registrar for

Edison International’s common

stock and Southern California

Edison Company’s preferred and

preference stock. Shareholders may

call Wells Fargo Shareowner

Services, (800) 347-8625, between

7 a.m. and 7 p.m. (Central Time),

Monday through Friday, to speak

with a representative (or to use the

interactive voice response unit 24

hours a day, seven days a week)

regarding:

n stock transfer and name-change

requirements;

n address changes, including

dividend payment addresses;

n electronic deposit of dividends;

n taxpayer identification number

submissions or changes;

n duplicate 1099 and W-9 forms;

notices of, and replacement of,

lost or destroyed stock certificates

and dividend checks;

n Edison International’s Dividend

Reinvestment and Direct Stock

Purchase Plan, including enroll-

ments, purchases, withdrawals,

terminations, transfers, sales,

duplicate statements, and direct

debit of optional cash for divi-

dend reinvestment; and requests

for access to online account

information.

Inquiries may also be directed to:

Wells Fargo Bank, N.A.

Shareowner Services Department

161 North Concord Exchange Street

South St. Paul, MN 55075-1139

Fax:

(651) 450-4033

Wells Fargo Shareowner ServicesSM

www.wellsfargo.com/

shareownerservices

Web Address

www.edisoninvestor.com

Online account information:

www.shareowneronline.com

Dividend Reinvestment and Direct Stock Purchase Plan

A prospectus and enrollment forms

for Edison International’s common

stock Dividend Reinvestment and

Direct Stock Purchase Plan are

available from Wells Fargo

Shareowner Services upon request.

Edison International Annual Report Shareholder Information

Table of Contents

3 Glossary

7 Management’s Discussion and Analysis of Financial Condition and Results of Operations117 Report of Independent Registered Public Accounting Firm

118 Consolidated Statements of Income

119 Consolidated Statements of Comprehensive Income

120 Consolidated Balance Sheets

122 Consolidated Statements of Cash Flows

124 Consolidated Statements of Changes in Common Shareholders’ Equity

125 Notes to Consolidated Financial Statements

196 Quarterly Financial Data

197 Selected Financial Data: 2004 — 2008

IBC Shareholder Information

1

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2

Glossary

When the following terms and abbreviations appear in the text of this report, they have the meanings indicatedbelow.

AB Assembly Bill

ACC Arizona Corporation CommissionAmeren Ameren Corporation

AFUDC allowance for funds used during construction

APS Arizona Public Service Company

ARO(s) asset retirement obligation(s)

Brooklyn Navy Yard Brooklyn Navy Yard Cogeneration Partners, L.P.

Btu British Thermal units

CAA Clean Air Act

CAIR Clean Air Interstate Rule

CAMR Clean Air Mercury Rule

CARB California Air Resources Board

Commonwealth Edison Commonwealth Edison Company

CDWR California Department of Water Resources

CEC California Energy Commission

CONE Cost of new entry

CPS Combined Pollutant Standard

CPSD Consumer Protection and Safety Division

CPUC California Public Utilities Commission

CRRs congestion revenue rights

D.C. District Court U.S. District Court for the District of Columbia

DOE United States Department of Energy

DOJ Department of Justice

DPV2 Devers-Palo Verde II

DRA Division of Ratepayer Advocates

DWP Los Angeles Department of Water & Power

EITF Emerging Issues Task ForceEITF No. 01-8 EITF Issue No. 01-8, Determining Whether an Arrangement Contains a Lease

EIA Energy Information Administration

EME Edison Mission Energy

EME Homer City EME Homer City Generation L.P.

EMG Edison Mission Group Inc.

EMMT Edison Mission Marketing & Trading, Inc.

EPAct 2005 Energy Policy Act of 2005

EPS earnings per share

ERRA energy resource recovery account

Exelon Generation Exelon Generation Company LLC

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

FGD flue gas desulfurization

FGIC Financial Guarantee Insurance Company

3

FIN 39-1 Financial Accounting Standards Board Interpretation No. 39-1, Amendment ofFASB Interpretation No. 39

FIN 46(R) Financial Accounting Standards Board Interpretation No. 46, Consolidation ofVariable Interest Entities

FIN 46(R)-6 Financial Accounting Standards Board Interpretation No. 46(R)-6, DeterminingVariability to be Considered in Applying FIN 46(R)

FIN 47 Financial Accounting Standards Board Interpretation No. 47, Accounting forConditional Asset Retirement Obligations

FIN 48 Financial Accounting Standards Board Interpretation No. 48, Accounting forUncertainty in Income Taxes – an interpretation of FAS 109

Fitch Fitch Ratings

FPA Federal Power Act

FSP FASB Staff Position

FSP FAS 13-2 FASB Staff Position FAS 13-2, Accounting for a Change or Projected Changein the Timing of Cash Flows Relating to Income Taxes Generated by aLeveraged Lease Transaction

FSP SFAS 142-3 FASB Staff Position No. SFAS 142-3, Determination of the Useful Life ofIntangible Assets

FTRs firm transmission rights

GAAP general accepted accounting principles

GHG greenhouse gas

Global Settlement A settlement that has been negotiated between Edison International and theIRS, which, if consummated, would resolve asserted deficiencies related toEdison International’s deferral of income taxes associated with certain of itscross-border, leveraged leases and all other outstanding tax disputes for opentax years 1986 through 2002, including certain affirmative claims forunrecognized tax benefits. There can be no assurance about the timing of suchsettlement or that a final settlement will be ultimately consummated.

GRC General Rate Case

GWh gigawatt-hours

Illinois EPA Illinois Environmental Protection Agency

Illinois Plants EME’s largest power plants (fossil fuel) located in Illinois

Investor-Owned Utilities SCE, SDG&E and PG&E

IPM a consortium comprised of International Power plc (70%) and Mitsui & Co.,Ltd. (30)%

IRS Internal Revenue Service

ISO California Independent System Operator

kWh(s) kilowatt-hour(s)

LIBOR London Interbank Offered Rate

MD&A Management’s Discussion and Analysis of Financial Condition and Results ofOperations

MECIBV MEC International B.V.

MEHC Mission Energy Holding Company

Midland Cogen Midland Cogeneration Venture

Midwest Generation Midwest Generation, LLC

MMBTU million British unitsMISO Midwest Independent Transmission System Operator

4

Glossary (continued)

Mohave Mohave Generating Station

Moody’s Moody’s Investors Service

MRTU Market Redesign Technology Upgrade

MW megawatts

MWh megawatt-hours

NAPP Northern Appalachian

Ninth Circuit United States Court of Appeals for the Ninth Circuit

NOV notice of violation

NOx nitrogen oxide

NRC Nuclear Regulatory Commission

NSR New Source Review

NYISO New York Independent System Operator

PADEP Pennsylvania Department of Environmental Protection

Palo Verde Palo Verde Nuclear Generating StationPBOP(s) postretirement benefits other than pension(s)

PBR performance-based ratemaking

PG&E Pacific Gas & Electric Company

PJM PJM Interconnection, LLC

POD Presiding Officer’s Decision

PRB Powder River Basin

PURPA Public Utility Regulatory Policies Act of 1978

PX California Power Exchange

QF(s) qualifying facility(ies)

RGGI Regional Greenhouse Gas Initiative

RICO Racketeer Influenced and Corrupt Organization

ROE return on equity

RPM reliability pricing model

S&P Standard & Poor’s

SAB Staff Accounting Bulletin

San Onofre San Onofre Nuclear Generating Station

SCAQMD South Coast Air Quality Management District

SCE Southern California Edison Company

SCR selective catalytic reduction

SDG&E San Diego Gas & Electric

SFAS Statement of Financial Accounting Standards issued by the FASB

SFAS No. 71 Statement of Financial Accounting Standards No. 71, Accounting for theEffects of Certain Types of Regulation

SFAS No. 98 Statement of Financial Accounting Standards No. 98, Sale-LeasebackTransactions Involving Real Estate

SFAS No. 115 Statement of Financial Accounting Standards No. 115, Accounting for certainInvestments in Debt and Equity Securities

SFAS No. 123(R) Statement of Financial Accounting Standards No. 123(R), Share-BasedPayment (revised 2004)

5


SFAS No. 133 Statement of Financial Accounting Standards No. 133, Accounting forDerivative Instruments and Hedging Activities

SFAS No. 141(R) Statement of Financial Accounting Standards No. 141(R), BusinessCombinations

SFAS No. 142 Statement of Financial Accounting Standards No. 142, Goodwill and OtherIntangible Assets

SFAS No. 143 Statement of Financial Accounting Standards No. 143, Accounting for AssetRetirement Obligations

SFAS No. 144 Statement of Financial Accounting Standards No. 144, Accounting for theImpairment or Disposal of Long-Lived Assets

SFAS No. 157 Statement of Financial Accounting Standards No. 157, Fair ValueMeasurements

SFAS No. 158 Statement of Financial Accounting Standards No. 158, Employers’ Accountingfor Defined Benefit Pension and Other Postretirement Plans

SFAS No. 159 Statement of Financial Accounting Standards No. 159, The Fair Value Optionfor Financial Assets and Financial Liabilities

SFAS No. 160 Statement of Financial Accounting Standards No. 160, Noncontrolling Interestsin Consolidated Financial Statements

SFAS No. 161 Statement of Financial Accounting Standards No. 161, Disclosures aboutDerivative Instruments and Hedging Activities, an amendment of FASBStatement No. 133

SIP(s) State Implementation Plan(s)

SNCR selective non-catalytic reduction

SO2 sulfur dioxide

SRP Salt River Project Agricultural Improvement and Power District

the Tribes Navajo Nation and Hopi Tribe

TURN The Utility Reform Network

US EPA United States Environmental Protection Agency

VIE(s) variable interest entity(ies)

6


Management’s Discussion and Analysis of Financial Condition and Results of Operations

INTRODUCTION

This MD&A contains “forward-looking statements” within the meaning of the Private Securities LitigationReform Act of 1995. Forward-looking statements reflect Edison International’s current expectations andprojections about future events based on Edison International’s knowledge of present facts and circumstancesand assumptions about future events and include any statement that does not directly relate to a historical orcurrent fact. Other information distributed by Edison International that is incorporated in this report, or thatrefers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere,the words “expects,” “believes,” “anticipates,” “estimates,” “projects,” “intends,” “plans,” “probable,” “may,”“will,” “could,” “would,” “should,” and variations of such words and similar expressions, or discussions ofstrategy or of plans, are intended to identify forward-looking statements. Such statements necessarily involverisks and uncertainties that could cause actual results to differ materially from those anticipated. Some of therisks, uncertainties and other important factors that could cause results to differ, or that otherwise could impactEdison International or its subsidiaries, include, but are not limited to:

• the cost of capital and the ability to borrow funds and access to capital markets on favorable terms,particularly in light of current credit conditions in the capital markets;

• the effect of current economic conditions on the availability and creditworthiness of counterparties and theresulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to payamounts owed in excess of collateral provided in support of their obligations;

• the ability to procure sufficient resources to meet expected customer needs in the event of significantcounterparty defaults under power-purchase agreements;

• changes in the fair value of investments and other assets;

• the ability of Edison International to meet its financial obligations and to pay dividends on its commonstock;

• the ability of SCE to recover its costs in a timely manner from its customers through regulated rates;

• decisions and other actions by the CPUC, the FERC and other regulatory authorities and delays inregulatory actions;

• market risks affecting SCE’s energy procurement activities;

• changes in interest rates, rates of inflation including those rates which may be adjusted by public utilityregulators, and foreign exchange rates;

• governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry,including the market structure rules applicable to each market;

• environmental laws and regulations, both at the state and federal levels, that could require additionalexpenditures or otherwise affect the cost and manner of doing business;

• risks associated with operating nuclear and other power generating facilities, including operating risks,nuclear fuel storage, equipment failure, availability, heat rate, output, availability and cost of spare parts,and cost of repairs and retrofits;

• the cost and availability of labor, equipment and materials;

• the ability to obtain sufficient insurance, including insurance relating to SCE’s nuclear facilities andwildfire-related liability, and to recover the costs of such insurance;

• effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes inaccounting standards;

7

• creditworthiness of suppliers and other project participants and their ability to deliver goods and servicesunder their contractual obligations to EME and its subsidiaries or to pay damages if they fail to fulfillthose obligations;

• the outcome of disputes with the IRS and other tax authorities regarding tax positions taken by EdisonInternational;

• the continued participation of Edison International’s subsidiaries in tax-allocation and payment agreements;

• supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in thewholesale markets to which EMG’s generating units have access;

• the cost and availability of coal, natural gas, fuel oil, nuclear fuel, and associated transportation to theextent not recovered through regulated rate cost escalation provisions or balancing accounts;

• the cost and availability of emission credits or allowances for emission credits;

• transmission congestion in and to each market area and the resulting differences in prices between deliverypoints;

• the ability to provide sufficient collateral in support of hedging activities and purchased power and fuel;

• the risk of counterparty default in hedging transactions or power-purchase and fuel contracts;

• the extent of additional supplies of capacity, energy and ancillary services from current competitors or newmarket entrants, including the development of new generation facilities and technologies;

• the difficulty of predicting wholesale prices, transmission congestion, energy demand and other aspects ofthe complex and volatile markets in which EMG and its subsidiaries participate;

• general political, economic and business conditions;

• weather conditions, natural disasters and other unforeseen events; and

• the risks inherent in the development of generation projects as well as transmission and distributioninfrastructure replacement and expansion including those related to siting, financing, construction,permitting, and governmental approvals.

Additional information about risks and uncertainties, including more detail about the factors described above,are discussed throughout this MD&A and in the “Risk Factors” section included in Part I, Item 1A of EdisonInternational’s Annual Report on Form 10-K. Readers are urged to read this entire report, including theinformation incorporated by reference, and carefully consider the risks, uncertainties and other factors thataffect Edison International’s business. Forward-looking statements speak only as of the date they are made andEdison International is not obligated to publicly update or revise forward-looking statements. Readers shouldreview future reports filed by Edison International with the Securities & Exchange Commission.

In this MD&A, except when stated to the contrary, references to each of Edison International, SCE, EMG,EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References toEdison International (parent) or parent company mean Edison International on a stand-alone basis, notconsolidated with its subsidiaries.

This MD&A is presented in 12 major sections. The company-by-company discussion of SCE, EMG, andEdison International (parent) includes discussions of liquidity, market risk exposures, and other matters (asrelevant to each principal business segment). The remaining sections discuss Edison International on aconsolidated basis. The consolidated sections should be read in conjunction with the discussion of eachcompany’s section.

8


Page

Edison International: Management Overview 10

Southern California Edison Company 16

Edison Mission Group Inc. 36Edison International (Parent) 61

Results of Operations and Historical Cash Flow Analysis 63

Discontinued Operations 85

Acquisitions and Dispositions 85

Critical Accounting Estimates and Policies 86

New Accounting Pronouncements 94

Commitments, Guarantees and Indemnities 94

Off-Balance Sheet Transactions 99

Other Developments 101

9

Edison International

EDISON INTERNATIONAL: MANAGEMENT OVERVIEW

Introduction

Edison International is a holding company whose principal operating subsidiaries are SCE, a rate-regulatedelectric utility, and EMG, the holding company of Edison International’s nonutility power generation (EME)and financial services (Edison Capital) segments. EME is engaged in the business of developing, acquiring,owning or leasing, operating and selling energy and capacity from independent power production facilities,and Edison Capital provides capital and financial services, with no plans to make new investments.

Areas of Business Focus

Financial Markets and Economic Conditions

Global financial markets are experiencing severe credit tightening and a significant increase in volatility,causing access to capital markets to become subject to increased uncertainty and borrowing costs. In response,U.S. and foreign governments and Central Banks have intervened with programs designed to increase liquidityand restore confidence.

Edison International’s subsidiaries are capital intensive businesses and depend on access to the financialmarkets to fund capital expenditures, meet contractual obligations, support energy procurement and marginand collateral requirements. SCE has significant planned capital expenditures to replace and expand itsdistribution and transmission infrastructure, and to construct and replace generation assets. EMG has expandedits business development activities to grow and diversify its existing portfolio of power projects, includingbuilding new power plants. In addition, EMG has environmental compliance requirements (discussed below)as well as ongoing capital expenditures for its existing generation fleet. Both SCE’s and EMG’s capital planswill require liquidity and access to capital markets at reasonable rates in the future. See “SCE: Liquidity,”“EMG: Liquidity,” and “Commitments, Guarantees and Indemnities” for further discussion.

Due to the instability of the financial markets and their participants, and to provide protection against aliquidity crisis, Edison International and its subsidiaries borrowed under their various credit facilities a total of$2.39 billion (including $1.29 billion for SCE, $851 million for EMG, and $250 million for EdisonInternational (parent)) during the second half of 2008, although there was no immediate need for such funds.As of December 31, 2008, Edison International had $5.57 billion of available liquidity made up of$3.92 billion of cash and short-term investments, as well as $1.65 billion remaining available under creditfacilities. In addition, in October 2008, SCE issued $500 million of 5.75% first and refunding mortgage bondsdue in 2014. The bond proceeds further augmented SCE’s cash position. Edison International and itssubsidiaries do not have any material long-term debt obligations that mature until 2012. See “SCE: Liquidity”and “EMG: Liquidity” for further discussion. While the capital markets are expected to recover over time, it isuncertain how long it will be before a recovery occurs. Long-term disruption in the capital markets couldadversely affect Edison International’s business plans and potentially impact Edison International’s financialposition.

SCE relies on power-purchase contracts to meet a significant portion of its resource requirements. Thefinancial crisis may adversely affect the ability of counterparties to access the capital markets, as needed, toperform under contracts upon which SCE will rely to meet new generation and renewables portfolio standardrequirements. Additionally, if counterparties fail to deliver under power-purchase contracts, SCE would beexposed to potentially volatile spot markets for buying replacement power, but would expect to recover anyadditional costs through regulatory mechanisms. The volatile market conditions have also affected the value oftrusts established at SCE to fund future long-term pension, other postretirement benefits, and nucleardecommissioning obligations. The market decline has decreased the funded status of these plans and unlessthe market recovers, will result in increased future expense and higher funding levels. SCE currently recoversand expects to continue to recover its pension, other postretirement benefits, and decommissioning costs,through customer rates and therefore funded cost increases are not expected to impact earnings, but may

10


impact the timing of cash flows (see “SCE: Liquidity” and “SCE: Other Developments” for furtherdiscussion).

SCE operates in a large and economically diverse service territory that covers central, coastal and southernCalifornia. Economic conditions are also affecting SCE’s customers and the demand for electricity.California’s economy is experiencing rising unemployment and increased foreclosures and bankruptcies.During 2008, SCE experienced a 10% increase in customer disconnects and a slight increase in the dollaramounts written off for uncollectible customer accounts, compared to 2007. In a February 2009 IntegratedEnergy Policy Report filed with the CEC for purposes of electricity resource planning, SCE forecast a 4.3%decrease in kWh sales in 2009, compared to 2008. About one-half of this decline is the result of a transitionfrom a warmer than normal summer in 2008 to a more typical summer in 2009. The CPUC-authorizeddecoupling revenue mechanisms allow for differences in revenue resulting from actual and forecast volumetricelectricity sales to be collected from or refunded to ratepayers and therefore insulate SCE’s short-termearnings from the economic contractions occurring in the U.S. and California. However, a prolonged period oflower sales could decrease future earnings as a result of lower levels of investment required to meet customerneeds. SCE’s rates are expected to increase in this period of economic downturn, which may further impactcustomers. See “SCE: Regulatory Matters — Impact of Regulatory Matters on Customer Rates,” “— 2009General Rate Case Proceeding,” and “— Energy Resource Recovery Account Proceedings” for furtherdiscussion. Under SCE’s tiered rate structure, rate increases are concentrated and not borne by all customers.

With respect to EMG, disruptions in the capital markets affected in 2008, and may continue to affect EMG’sability to finance already-developed wind projects and future commitments and projects, including significantoutstanding capital commitments for wind turbines. Furthermore, these disruptions may affect how EMGaddresses its commitments with respect to environmental compliance, as discussed below. As a result, pendingrecovery of the capital markets, EMG intends to preserve capital by focusing on a selective growth strategy(primarily completion of projects under construction, including the Big Sky wind project in Illinois, anddevelopment of sites for future renewable projects deploying current turbine commitments), and using its cashand future cash flow to meet existing contractual commitments. Depending upon financing conditions, EMGmay elect to postpone and/or cancel wind turbine commitments, subject to the provisions of the relevantcontracts. See “EMG: Liquidity — Capital Expenditures” and “Commitments, Guarantees and Indemnities —Turbine Commitments” for further discussion. Moreover, disruption in the financial markets appears to havereduced trading activity in power markets which may affect the level and duration of future hedging activityand potentially increase the volatility of earnings. Long-term disruption in the capital markets could adverselyaffect EME’s business plans and financial position.

The American Recovery and Reinvestment Act of 2009

President Obama signed the American Recovery and Reinvestment Act of 2009 (the “Act”) into law onFebruary 17, 2009. The law contains direct spending measures and tax cuts totaling approximately$787 billion. The Act provides production tax credits for a ten-year period for new wind projects placed inservice prior to December 31, 2012 and provides that, in lieu of the production tax credit, renewabledevelopers may make an election to claim either a 30% investment tax credit or a grant for a 30%reimbursement of expenses associated with specified energy property. The Act also contains a one yearextension of the 50% bonus depreciation, with an extra year available for long lived property, which includestransmission and distribution assets. Energy spending initiatives in the Act include: $6 billion in loanguarantees for renewable energy and transmission, $4.5 billion to be spent on smart grid investments,$5 billion for weatherization and $3.1 billion in state energy program funds to promote energy efficiency. TheAct provides significant support to plug-in hybrid electric vehicle commercialization, including $2 billion ingrants for advanced batteries and new or enhanced tax credits for vehicle manufacturing, infrastructure andvehicle purchases, as well as $400 million for port and truck-stop electrification.

11


Commodity Prices

The market price for merchant energy in PJM increased significantly during the first half of 2008 and thendecreased significantly in the second half of the year. The average 24-hour PJM market price for energy perMWh at the Northern Illinois Hub and Homer City busbar was higher in 2008 as compared to 2007 by 7.6%and 13.1%, respectively. However, since June 30, 2008, forward energy prices in PJM have decreasedsubstantially driven by lower natural gas prices and the financial market developments discussed above. AtDecember 31, 2008, forward energy market prices for 2009 for the Northern Illinois Hub and PJM West Hubhave decreased by 38% and 42%, respectively, since June 30, 2008. At the same time, the average cost of fuelper MWh increased in 2008 by 16% at Midwest Generation and 4% at EME Homer City. At December 31,2008, Midwest Generation and EME Homer City had contracted for substantially all of their coal requirementsfor 2009. Unless these energy prices change, energy gross margins for unhedged volumes from MidwestGeneration and EME Homer City will decrease from 2008. See “Market Risk Exposures — Commodity PriceRisk” for further discussion.

SCE purchases approximately 44% of its resource needs. SCE expects that these purchases could increasesignificantly as the CDWR energy contracts are phased out by 2011 and SCE enters into new or novatedcontracts to replace or assume responsibility for the energy supplied from the CDWR contracts. In addition toSCE’s Mountainview and peaker plants, approximately 46% of SCE’s power purchase requirements are subjectto natural gas price volatility. Natural gas prices increased significantly during the first half of 2008 anddecreased significantly in the second half of the year. Because SCE recovers its procurement costs through theERRA balancing account mechanism, these market fluctuations do not impact earnings, but can build rapidlyand can greatly impact cash flow and customer rates. See “Current Regulatory Developments — Impact ofRegulatory Matters on Customer Rates” and “— Energy Resource Recovery Account Proceedings.”

Growth Activities and Capital Commitments

Although SCE is experiencing significant growth in actual and planned capital expenditures to improvereliability and expand capability of its distribution and transmission infrastructure, to construct and replacegeneration assets, and to deploy advanced metering infrastructure, the level of future growth is dependent on afinal outcome of its 2009 GRC and other pending CPUC and FERC proceedings. SCE’s 2009 through 2013capital investment plan includes total capital spending in the range of $17.1 billion to $21 billion. See “SCE:Regulatory Matters — Current Regulatory Developments — 2009 General Rate Case Proceeding,” and “SCE:Liquidity — Capital Expenditures” for further discussions. These plans would involve the most significantinfrastructure build-out of its kind that SCE has undertaken in years. The completion of the projects, thetiming of expenditures, and the associated recovery may be affected by permitting requirements and delays,construction delays, availability of labor, equipment and materials, financing, legal and regulatorydevelopments, weather, economic conditions and other unforeseen conditions. In addition, SCE has pendingFERC proceedings related to its 2009 FERC Rate Case and CWIP incentive filings that may further impactSCE’s capital investment plan.

As a result of the financial markets and economic condition, discussed above, EMG intends to focus on amore selective growth strategy as described above. At December 31, 2008, EME had 962 MW of windprojects in service and three wind projects under construction with an EME pro rata share of 223 MW, withscheduled completion dates during 2009. EME’s wind projects under construction are currently funded throughequity. EME has contracts to purchase 942 MW of new turbines with scheduled payment obligations of up to$706 million in 2009 and $232 million in 2010. EME plans to use a portion of these turbines to complete a240 MW planned wind project in Illinois, referred to as the Big Sky wind project. EME plans to use theremaining turbines to support construction of new projects, subject to meeting investment criteria andavailability of financing. See “EMG: Liquidity — Capital Expenditures” and “Commitments, Guarantees andIndemnities — Turbine Commitments” for further discussion.

12


Federal and State Income Taxes

Edison International has negotiated the material terms of a Global Settlement with the IRS which, ifconsummated, would resolve cross-border, leveraged lease issues in their entirety and all other outstanding taxdisputes for open tax years 1986 through 2002, including certain affirmative claims for unrecognized taxbenefits. See “Edison International Notes to Consolidated Financial Statements — Note 4. Income Taxes.”Consummation of the Global Settlement is subject to review by the Staff of the Joint Committee on Taxation,a committee of the United States Congress (the “Joint Committee”). The IRS submitted the pertinent terms ofthe Global Settlement to the Joint Committee during the fourth quarter of 2008, and its response is currentlypending. Edison International cannot predict when such review will be completed or the outcome of suchreview. See “Other Developments — Federal and State Income Taxes” for further information.

Environmental Developments

Climate Change Regulation

The content of potential climate change regulation in the future remains uncertain. While debate continues atthe national level over domestic climate policy and the appropriate scope and terms of any federal legislation,many states are developing state-specific measures or participating in regional legislative initiatives to reduceGHG emissions. State and regional regulations may vary and may be more stringent and costly than federallegislative proposals currently being debated in U.S. Congress. Key uncertainties include whether acap-and-trade program will be implemented similar to the US EPA Acid Rain Program, and, if implemented,whether emission allowances would be provided to affected parties without cost for a period of time. In theabsence of legislation, it is also possible that CO2 will be regulated by the US EPA pursuant to authoritygranted under the CAA in its current form. Furthermore, the rate of decrease in GHG emissions and the costto purchase allowances would be significant factors in determining whether environmental controls for otheremissions would be economic to install. Programs to reduce GHG emissions could significantly increase thecost of generating electricity from fossil fuels as well as the cost of purchased power. In the case of utilities,like SCE, these costs are generally borne by customers, whereas the increased costs for competitive generationmust be recovered through market prices for electricity. The potential impact on Edison International’ssubsidiaries will depend upon how the factors discussed above and many other considerations are resolved.

In the absence of any federally imposed climate change regulation, California’s Global Warming Solutions Actof 2006 (also known as AB32) set an overall goal of reducing GHG emissions to 1990 levels by 2020. Theprogram, which is being established by the CARB, to implement AB32 includes, among other measures, anincrease to the existing CPUC-imposed renewables portfolio standard of 20% by 2010 to a 33% renewablesprocurement standard by 2020. Compliance with the 33% renewables portfolio standard would require, amongother items, substantial additional power purchase contracts and capital expenditures to expand SCE’sdistribution and transmission infrastructure, all at a significant cost.

Air Quality Regulations in Illinois

On December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA to reducemercury, NOx and SO2 emissions at the Illinois Plants. The agreement has been embodied in an Illinois rulecalled the CPS. All of the Midwest Generation’s Illinois coal-fired electric generating units are subject to theCPS.

Under the CPS, Midwest Generation is required to achieve specific lower emission rates by specified dates.Midwest Generation has not decided upon a particular combination of retrofits to meet the required step downin emission rates. Midwest Generation continues to review alternatives, including interim compliancesolutions. The CPS also specifies that specific control technologies are to be installed on some units byspecified dates. In these cases, Midwest Generation must either install the required technology by the specifieddeadline or shut down the unit.

13


Midwest Generation is in the process of completing engineering work for the potential installation of SCRequipment on Units 5 and 6 at the Powerton Station and SNCR equipment on Unit 6 at the Joliet Station. TheSCR equipment at Powerton is currently estimated to cost $500 million and the SNCR equipment on Unit 6 atthe Joliet Station is currently estimated to cost $13 million (both figures are in 2008 dollars). This technologycombination represents one possible compliance plan for the NOx emission rates. Midwest Generation isevaluating other potential solutions that are less costly to meet the NOx emissions rate that combine the use ofalternative NOx removal technologies with certain unit shutdowns.

The engineering work at the Powerton Station also includes the potential installation of FGD equipment onUnits 5 and 6, and Midwest Generation currently estimates approximately $1 billion (in 2008 dollars) ofcapital expenditures would be required for the FGD equipment at the Powerton Station. Midwest Generationalso determined these capital expenditures could be reduced if the construction work sequence of FGD andSCR at the Powerton Station were reversed. The complexity of the Powerton Station installation andconstruction interferences are representative of the balance of the fleet and Midwest Generation currentlyestimates approximately $650/kW for any FGD installation it elects to make on other units.

A decision to make these improvements has not been made. Midwest Generation is still evaluating alltechnology and unit shutdown combinations, including interim and alternative compliance solutions. Forfurther discussion, see “Other Developments — Environmental Matters — Air Quality Regulation.”

Water Quality Regulations

Federal water quality regulations regulate the discharge of pollutants into federal waters, the heat of effluentdischarges and the location, design and construction of cooling water intake structures at generation facilities.State regulations also cover certain discharges that are not regulated at the federal level.

In the absence of federal regulations, which are currently the subject of litigation and rulemaking, California isdeveloping a policy on ocean-based once-through cooling structures, although the timing of such policybecoming effective is uncertain. The policy is expected to have a substantial effect on grid reliability in theCAISO service area, including on operations at San Onofre and on SCE’s ability to procure generatingcapacity from fossil-fueled plants using ocean water once-through cooling systems. As of December 31, 2008,approximately 18,500 MW in the CAISO service area would be subject to this once-through cooling policy.

On October 26, 2007, the Illinois EPA filed a proposed rule with the Illinois Pollution Control Board thatwould establish more stringent thermal and effluent water quality standards for the Chicago Area WaterwaySystem and Lower Des Plaines River. Midwest Generation’s Fisk, Crawford and Will County Stations all usewater from the Chicago Area Waterway System and its Joliet Station uses water from the Lower Des PlainesRiver for cooling purposes. The rule, if implemented, is expected to affect the manner in which those stationsuse water for station cooling.

The proposed rule is the subject of an administrative proceeding before the Illinois Pollution Control Boardand must be approved by the Illinois Pollution Control Board and the Illinois Joint Committee onAdministrative Rules. Following state adoption and approval, the US EPA also must approve the rule.Hearings began on January 28, 2008, and are continuing in 2009. Midwest Generation is a party in thoseproceedings. At this time, it is not possible to predict the timing for resolution of the proceeding, the finalform of the rule, or how it would impact the operation of the affected stations; however, significant capitalexpenditures may be required depending on the form of the final rule. In addition, the outcome of theseproceedings may affect Midwest Generation’s plans for compliance with CPS discussed above.

See “Other Developments — Environmental Matters” for a further discussion of these and other environmentalmatters.

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2008 Earnings Performance

The table below presents Edison International’s earnings for the years ended December 31, 2008, 2007 and2006, and the relative contributions by its subsidiaries.

In millions Year Ended December 31, 2008 2007 2006

Earnings (Loss)

Earnings (Loss) from Continuing Operations:SCE $ 683 $ 707 $ 776EMG 561 412 334Edison International (parent) and other (29) (19) (27)

Edison International Consolidated Earnings from Continuing Operations 1,215 1,100 1,083

Earnings (Loss) from Discontinued Operations — (2) 97

Cumulative effect of accounting change – net of tax — — 1

Edison International Consolidated $ 1,215 $ 1,098 $ 1,181

Earnings (Loss) from Continuing Operations

2008 vs. 2007

SCE’s earnings from continuing operations were $683 million in 2008, compared with earnings of$707 million in 2007. The decrease in 2008 was mainly attributable to a $49 million charge associated withthe CPUC decision on SCE’s performance-based ratemaking mechanism recorded in 2008 and a $31 milliontax benefit from the resolution of the income tax treatment of certain environmental remediation costsrecorded in 2007, partially offset by higher operating income related to rule base growth, including authorizedenergy efficiency incentives, and lower net interest expense.

EMG’s earnings from continuing operations were $561 million in 2008, compared with earnings of$412 million in 2007. EMG’s 2008 increase was mainly due to a $148 million, after tax, loss on earlyextinguishment of debt recorded in 2007, higher operating income at EMG’s Midwest Generation, positiveresults from new wind projects in operation, and higher trading income at EMMT. These earnings were offsetby lower results from the Big 4 projects, lower interest income, a loss arising from the termination of a naturalgas turbine supply agreement, and lower results at EMG’s Homer City facilities and Edison Capital.

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SOUTHERN CALIFORNIA EDISON COMPANY

SCE: REGULATORY MATTERS

Overview of Ratemaking Mechanisms

SCE is an investor-owned utility company providing electricity to retail customers in central, coastal andsouthern California. SCE is regulated by the CPUC and the FERC. SCE bills its retail customers for the saleof electricity at rates authorized by the CPUC. These rates are discussed below under four categories: baserates, cost-recovery rates, energy efficiency incentives and CDWR-related rates. SCE sells unbundledtransmission service and wholesale power at rates and under tariffs authorized by the FERC.

Base Rates

Revenue arising from base rates from the CPUC and the FERC are designed to provide SCE a reasonableopportunity to recover its costs and earn an authorized return on SCE’s net investment in generation,transmission and distribution facilities (or rate base). These base rates provide for recovery of operations andmaintenance costs, capital-related carrying costs (depreciation, taxes and interest) and a return or profit, on aforecast basis.

Base rates related to SCE’s generation and distribution functions are authorized by the CPUC through atriennial process called the GRC. In a GRC proceeding, SCE files an application with the CPUC to update itsauthorized annual revenue requirement for a base year and two subsequent years. After a review process andhearings, the CPUC sets an annual revenue requirement for the base year which is made up of the carryingcost on capital investment (depreciation, return and taxes), plus the authorized level of operation andmaintenance expense. The return is established by multiplying an authorized rate of return, determined in theseparate cost of capital proceedings (as discussed below), by rate base (the value of assets on which SCE earnsa rate of return for investors). In its GRC proceedings, SCE also submits testimony regarding its need forcapital spending on a forecast basis which is reviewed and approved, if found reasonable by the CPUC.Adjustments to the revenue requirement for the remaining two years of a typical three-year GRC cycle arerequested from the CPUC, based on criteria established in the GRC proceeding which generally includeannual allowances for escalation in operation and maintenance costs, forecasted changes in capital-relatedinvestments and related costs and the timing and number of expected nuclear refueling outages and theirrelated forecasted costs. See “— Current Regulatory Developments — 2009 General Rate Case Proceeding”for SCE’s current annual revenue requirement.

The CPUC-authorized decoupling revenue mechanisms allow for differences in revenue resulting from actualand forecast volumetric electricity sales to be collected from or refunded to ratepayers and therefore do notimpact SCE’s earnings. Differences between authorized and actual operating costs, other than cost-recoverycosts (see below), do impact earnings.

Base rate revenue related to SCE’s transmission facilities are authorized by the FERC, as needed, in periodicproceedings that are similar to the CPUC’s GRC proceeding, except that requested rate changes are generallyimplemented either 60 days after the application is filed or after a maximum five month suspension. Revenuecollected prior to a final FERC decision is recognized as revenue, but is subject to refund. Revenue authorizedunder FERC jurisdiction that varies from forecast is not subject to balancing account mechanisms, is notrecoverable or refundable and can therefore impact operating returns.

SCE’s capital structure and related authorized rate of return, is regulated by the CPUC and the FERC. TheCPUC jurisdictional cost of capital is applicable to the costs requested through CPUC jurisdictional base rates.The FERC jurisdictional cost of capital is applicable to FERC jurisdictional base rates designed to recovertransmission costs. Currently, the CPUC determines SCE’s cost of capital in a multi-year proceeding occurringevery three years. SCE expects that the current capital structure and authorized rate of return will remain inplace until January 2011, absent any potential annual adjustment, as discussed below. SCE’s current authorized

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capital structure is 48% common equity, 43% long-term debt and 9% preferred equity. SCE’s currentauthorized cost of long-term debt is 6.22%, authorized cost of preferred equity is 6.01% and authorized returnon common equity is 11.5%. The three-year cost of capital mechanism provides for an automatic readjustmentto SCE’s capital costs during the years between the cost of capital filings if certain thresholds are reached onan annual basis. SCE’s next potential adjustment will occur at the end of September 2009, effective for 2010.As a result, depending on financial market conditions, SCE is subject to the potential earnings impact ofactual financing costs being above or below its authorized rates of 6.22% and 6.01% for new long-term debtand preferred equity financings, respectively, during 2009.

Cost-Recovery Rates

Revenue requirements to recover SCE’s costs of fuel, purchased-power, demand-side management programs,nuclear decommissioning, public purpose programs, certain operation and maintenance expenses, anddepreciation expense related to certain projects are authorized in various CPUC proceedings on a cost-recoverybasis, with no markup for return or profit. Approximately 62% of SCE’s annual revenue relates to the recoveryof these costs. Although the CPUC authorizes balancing account mechanisms to refund or recover anydifferences between forecasted and actual costs, under- or over-collections in these balancing accounts canbuild rapidly due to fluctuating prices (particularly for purchased-power) and can greatly impact cash flows.The majority of costs eligible for recovery through cost-recovery rates are subject to CPUC reasonablenessreviews, and thus could negatively impact earnings and cash flows if found to be unreasonable and disallowed.

Energy Efficiency Shareholder Risk/Reward Incentive Mechanism

The CPUC has adopted an Energy Efficiency Risk/Reward Incentive Mechanism covering two three-yearperiods (2006 – 2008 and 2009 – 2011). The mechanism allows for both financial incentives and economicpenalties based on SCE’s performance toward meeting CPUC goals for energy efficiency. Under thismechanism, SCE has the opportunity to earn an incentive of 9% of the value of total energy efficiency savingsif it achieves between 85% and 100% of its energy efficiency goals for the cumulative three year period or canearn 12% of the value of energy efficiency savings if 100% or greater of its goals are achieved. Economicpenalties would be imposed in the event SCE achieves less than 65% of its goals. The mechanism has adeadband between 65% and 85% of energy efficiency goals, where no economic penalty or incentive would beearned. The mechanism allows for two progress payments, subject to a 35% holdback, for estimated progresstowards meeting CPUC-authorized 3-year goals and a third payment for final measured performance towardsthose goals, which includes the payment of any holdback. SCE may retain the first and second progresspayments as long as it meets a minimum of 65% of the goals, as measured by the CPUC in the final payment.If SCE falls below the 65% level, the amount of the progress payments and economic penalties would bededucted from future earnings awards. Both incentives and economic penalties for each three-year period arecapped at $200 million. There is no assurance that SCE will meet its goals of energy efficiency incentiveearnings in any given year. In addition, certain aspects of the energy efficiency incentive mechanism remainsubject to CPUC review and possible modification. See “Current Regulatory Developments — EnergyEfficiency Shareholder Risk/Reward Incentive Mechanism” for further discussion of current developmentsrelated to the 2006 – 2008 program cycle.

CDWR-Related Rates

As a result of the California energy crisis, in 2001 the CDWR entered into contracts to purchase power forsale at cost directly to SCE’s retail customers and issued bonds to finance those power purchases. TheCDWR’s total statewide power charge and bond charge revenue requirements are allocated by the CPUCamong the customers of the Investor-Owned Utilities. SCE bills and collects from its customers the costs ofpower purchased and sold by the CDWR, CDWR bond-related charges and direct access exit fees. TheCDWR-related charges and a portion of direct access exit fees (approximately $2.2 billion was collected in2008) are remitted directly to the CDWR, are not recognized as electric utility revenue by SCE and therefore

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have no impact on SCE’s earnings; however, they do impact customer rates. See “— Impact of RegulatoryMatters on Customer Rates” for further discussion.

Current Regulatory Developments

This section of the MD&A describes significant regulatory issues that may impact SCE’s financial conditionor results of operations.

Impact of Regulatory Matters on Customer Rates

Throughout the year, SCE changes rates to implement various regulatory decisions. SCE’s current systemaverage rate is 13.7¢ per-kWh (2.8¢ per-kWh related to CDWR, which is not recognized as revenue by SCE).

SCE expects to implement a rate change March 1, 2009 related to 2009 procurement-related costs and the2009 FERC rate case offset by decreases in the 2009 CDWR power charge revenue requirement. This ratechange is expected to result in a system average rate of 13.4¢ per-kWh (2.3¢ per-kWh related to CDWR,which is not recognized as revenue by SCE). See “— Energy Resource Recovery Account Proceedings —2008 ERRA Revenue Requirements Forecast” and “— 2009 FERC Rate Case” for further information.

During the 2001 energy crisis, the California Legislature passed a bill, AB 1X, which implemented a tieredrate structure that capped, or fixed, the rates for almost half of SCE’s residential customers. As a result, anyresidential revenue requirement increase is allocated to the remaining residential customers. This causes widevariation in the average rates SCE’s residential customers pay. This rate inequity is causing increasingly highbills for a subset of SCE’s customers. SCE is currently working with the CPUC, consumer groups, and keyCalifornia public officials to seek support for a means to mitigate the effects of AB 1X.

In May 2007, the CPUC initiated a rulemaking to determine whether, or subject to what conditions, directaccess could be restored in California. The proceeding was initially divided into three phases, with the firstphase addressing whether the CPUC had the legal authority to lift the suspension of direct access underAB 1X. In February 2008, the CPUC issued a decision, finding that the CPUC could not lift the direct accesssuspension as long as the CDWR continues to supply power to retail customers as a party to its existing powercontracts. The reopening of Direct Access may have an impact on customer rates, however, SCE is unable topredict the outcome or impact of this process at this time.

In November 2008, the CPUC issued a subsequent decision, finding that there are sufficient potential benefitsto ratepayers to establish a process that phases-out the CDWR’s remaining involvement in supplying power toInvestor-Owned Utility customers. The November 2008 decision sets a target goal of novating/replacing byJanuary 1, 2010 all remaining CDWR energy contracts so that the novated/replacement contracts are heldinstead by the Investor-Owned Utilities. SCE cannot predict whether or not the expedited phase-out of theCDWR contracts will occur on commercially feasible terms and the outcome of the financial impact on SCE.

2009 General Rate Case Proceeding

In February 2009, the Administrative Law Judge issued a revised proposed decision on SCE’s 2009 GRC. Inaddition, CPUC President Peevey further revised his alternate proposed decision in this proceeding. TheAdministrative Law Judge’s revised proposed decision would authorize a $4.6 billion base revenuerequirement for 2009, a 24% increase over the 2006 authorized revenue requirement of $3.7 billion and baserevenue requirements of $4.8 billion in 2010 and $4.9 billion in 2011. If adopted as currently drafted, thisproposed decision would require SCE to reduce its planned capital expenditures in 2009 and 2010 by$2.0 billion with further reductions to be made in 2011, and reduce its forecast operating and maintenanceexpenditures by more than $400 million. The impacts of these expenditure reductions may compromise SCE’sability to comply with regulatory requirements, maintain its electric system, and provide reliable service to itscustomers. CPUC President Peevey’s revised alternate proposed decision would authorize a $4.9 billion baserevenue requirement for 2009, a 30% increase over the 2006 authorized revenue requirement of $3.7 billion,

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and a methodology for calculating post-test year revenue requirements that would result in an approximaterevenue requirement of $5.1 billion in 2010 and $5.4 billion in 2011. While the revised alternate proposeddecision authorizes revenue requirements below the level requested in SCE’s GRC Application, if adopted ascurrently drafted, the proposed decision would provide SCE adequate funding to serve its customers. See“SCE: Liquidity” for further discussion of the impact on capital spending.

Both alternate decisions grant SCE’s request for the authority to transfer the assets and liabilities ofMountainview Power Company, LLC to SCE. This transfer would facilitate operations of the power plant andreduce administrative compliance requirements. If approved, SCE would expect to record one-time accountinggains of $49 million and $14 million in the form of regulatory assets to recognize differences in theaccounting treatment for non-regulated and rate-regulated entities related to equity AFUDC, and capitalizationof acquisition costs, respectively. There would be no economic impact to customers from this change ascompared to the existing FERC-approved power-purchase agreement; as these amounts would have beenrecognized over the life of that agreement and have no impact on cash flows. The transfer of MountainviewPower Company, LLC to SCE is also subject to FERC approval which is dependent on final approval ofSCE’s 2009 GRC Application.

SCE cannot predict whether the CPUC will ultimately adopt one or the other of these proposed decisions.

Energy Efficiency Shareholder Risk/Reward Incentive Mechanism

As described above under the heading “ — Overview of Ratemaking Mechanisms — Energy EfficiencyShareholder Risk/Reward Incentive Mechanism,” the CPUC has adopted an Energy Efficiency Risk/RewardIncentive Mechanism. Under the mechanism, if SCE achieves all of its energy efficiency goals, and deliverscustomer benefits of approximately $1.2 billion, the three-year earnings opportunity for the 2006 – 2008period would be approximately $146 million pre-tax. On December 18, 2008, the CPUC approved SCE’s firstprogress payment for 2006 – 2007 energy efficiency performances using SCE’s quarterly savings report ratherthan the CPUC verification report which was delayed. However, the CPUC increased the holdback percentage(for this progress payment only) from the originally authorized 35%, to 65%, resulting in a first progresspayment of $25 million which is expected to be collected through rates in 2009. The DRA and TURN filed arequest for rehearing of the December decision approving the first progress payment. SCE does not believe therequest for rehearing will affect the first progress payment award but cannot predict the outcome of thisproceeding.

Pursuant to the adopted mechanism, future progress payments are expected to be based on CPUC verificationreports. If the CPUC’s verification report is again delayed in 2009, the CPUC may approve the secondprogress payment based upon SCE’s quarterly savings report, subject to another review of the progresspayment holdback percentage. Currently, SCE intends to file its request for its second progress payment usingSCE’s final quarterly savings report on March 2, 2009 for the second progress payment. SCE currentlyprojects (using a 65% holdback percentage), based on preliminary results and on the current energy efficiencymechanism guidelines, that it will record a second progress payment in the range of $14 million to$26 million upon CPUC approval, which is expected in the fourth quarter of 2009 for the 2006 – 2008program cycle. SCE expects to collect this progress payment in rates in 2010. Based on the currentmechanism, SCE estimates that it will meet 100% of its energy efficiency goals for the 2006 – 2008 period.

On January 29, 2009, the CPUC issued a new rulemaking intended to address issues with the currentmechanism, including delays in the verification process, utility concerns about methodologies used by theCPUC Energy Division in calculating interim incentive payments, and intervenors’ concerns about the fairnessof the incentive structure. In this rulemaking the CPUC intends to adopt a new framework for the review ofthe remainder of 2006 – 2008 energy efficiency activities in a timeframe consistent with interim payments for2008 no later than December 2009, and any final payments for 2006 – 2008 no later than December 2010.There is no assurance of earnings in any given year or that the mechanism will not be changed as a result ofthe rulemaking issued by the CPUC in January 2009.

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2009 FERC Rate Case

In an order issued in September 2008, the FERC accepted and made effective on March 1, 2009, subject torefund and settlement procedures, SCE’s proposed revisions to its tariff, filed in the 2009 transmission ratecase. The revisions reflected changes to SCE’s transmission revenue requirement and transmission rates, asdiscussed below.

SCE requested a $129 million increase in its retail transmission revenue requirements (or a 39% increase overthe current retail transmission revenue requirement) due to an increase in transmission capital-related costs andincreases in transmission operating and maintenance expenses that SCE expects to incur in 2009 to maintaingrid reliability. The transmission revenue requirement request is based on a return on equity of 12.7%, whichis composed of a 12.0% base ROE and 0.7% in transmission incentives previously approved by the FERC (see“— FERC Transmission Incentives” below for further information). SCE is unable to predict the revenuerequirement that the FERC will ultimately authorize.

FERC Transmission Incentives

The Energy Policy Act of 2005 established incentive-based rate treatments for the transmission of electricenergy in interstate commerce by public utilities for the purpose of benefiting consumers by ensuringreliability and reducing the cost of delivered power by reducing transmission congestion. Pursuant to this act,in November 2007, the FERC issued an order granting incentives on three of SCE’s largest proposedtransmission projects. These include 125 basis point ROE adders on SCE’s proposed base ROE for SCE’sDPV2 and Tehachapi transmission projects and a 75 basis point ROE adder for SCE’s Rancho VistaSubstation Project (“Rancho Vista”).

In June 2007, the ACC denied the approval of the DPV2 project which resulted in an estimated two year delayof the project. SCE continues its efforts to obtain the regulatory approvals necessary to construct the DPV2project and continues to evaluate its options, which include but are not limited to, filing a new applicationwith the ACC and building the project in various phases.

The order also grants a 50 basis point ROE adder on SCE’s cost of capital for its entire transmission rate basein SCE’s next FERC transmission rate case for SCE’s participation in the CAISO. In addition, the order onincentives permits SCE to include in rate base 100% of prudently-incurred capital expenditures duringconstruction, also known as CWIP, of all three projects and 100% recovery of prudently-incurred abandonedplant costs for two of the projects, if either are cancelled due to factors beyond SCE’s control.

In August 2008, the CPUC filed an appeal of the FERC incentives order at the DC Circuit Court of Appeals.The court issued a ruling on November 6, 2008, accepting the CPUC’s request that the court refrain fromruling on the CPUC’s appeal until a final FERC order is issued in the 2008 CWIP case (see “— FERCConstruction Work in Progress Mechanism” below for further information).

FERC Construction Work in Progress Mechanism

FERC CWIP 2008

In February 2008, the FERC approved SCE’s revision to its tariff to collect 100% of CWIP in rate base for itsTehachapi, DPV2, and Rancho Vista, as authorized by FERC in its transmission incentives order discussedabove which resulted in an authorized base transmission revenue requirement of $45 million, subject to refund.In March 2008, the CPUC filed a petition for rehearing with the FERC on the FERC’s acceptance of SCE’sproposed ROE for CWIP and in another 2008 protest to an SCE compliance filing, requested an evidentiaryhearing to be set to further review SCE’s costs. SCE cannot predict the outcome of the matters in thisproceeding.

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FERC CWIP 2009

SCE filed its 2009 CWIP rate adjustment in October 2008 proposing a reduction to its CWIP revenuerequirement from $45 million to $39 million to be effective on January 1, 2009. Several parties, including theCPUC, filed protests to the October filing in November 2008, primarily contesting SCE’s proposed base ROEof 12.0%. The FERC issued an order in December 2008, allowing the proposed 2009 CWIP rates to go intoeffect on January 1, 2009, subject to refund, and directing that the 2009 CWIP ROE be made subject to theoutcome of the pending 2008 FERC CWIP proceeding. The FERC also consolidated all issues other than ROEwith SCE’s 2009 FERC rate case proceeding (see “2009 FERC Rate Case” above for further information).

Energy Resource Recovery Account Proceedings

The ERRA is the balancing account mechanism that tracks and recovers SCE’s fuel and procurement-relatedcosts. SCE files annual forecasts of these costs that it expects to incur during the following year and sets ratesusing forecasts. At December 31, 2008, the ERRA was under-collected by $406 million, which was 7.6% ofSCE’s prior year’s generation revenue. The CPUC has established a “trigger” mechanism that allows for a rateadjustment if the ERRA balancing account overcollection or undercollection exceeds 5% of SCE’s prior year’sgeneration revenue. Due to the recent decrease in natural gas prices, SCE estimates that the ERRA balancingaccount undercollection will be below the trigger threshold by June 2009. Therefore, SCE does not expect tofile a trigger application.

2009 ERRA Revenue Requirements Forecast

On January 29, 2009, the CPUC approved SCE’s proposal that an increase of $331 million over SCE’sadopted 2008 ERRA revenue requirement be reflected in rate levels (which results in a 2009 ERRA revenuerequirement of $4.0 billion). The adopted 2009 ERRA revenue requirement change will be implemented inrates on March 1, 2009. The CPUC further agreed to let SCE net a projected $110 million decrease in its2009 procurement costs against the remaining under-collected ERRA balance in the future and rely on timelytrigger applications for additional recovery needs.

Resource Adequacy Requirements

Under the CPUC’s resource adequacy framework, all load-serving entities in California have an obligation toprocure sufficient resources to meet their expected customers’ needs on a system-wide basis with a 15 – 17%reserve level. In addition, on June 6, 2006, the CPUC adopted local resource adequacy requirements.

SCE is required to demonstrate every month that it has met 100% of its system resource adequacy requirementone month in advance of expected need (known as the month-ahead system resource adequacy showing). SCEis also required to make its year-ahead system resource adequacy showing (90% threshold) in the fall of thecalendar year prior to the compliance year. The system resource adequacy requirements provide for penaltiesof 300% of the cost of new monthly capacity for failing to meet the system resource adequacy requirements.Under the local resource adequacy requirements, SCE must demonstrate on an annual basis that it hasprocured 100% of its requirement within defined local areas. The local resource adequacy requirementsprovide for penalties of 100% of the cost of new monthly capacity for failing to meet the local resourceadequacy requirements. SCE demonstrated its compliance with the resource adequacy requirements in 2008,expects to be in compliance in 2009 and does not expect to incur any resource adequacy program penalties.

Peaker Plant Generation Projects

In August 2006, the CPUC issued a ruling addressing electric reliability needs in Southern California forsummer 2007 that directed SCE, among other things, to pursue new utility-owned peaker generation thatwould be online by August 2007. In response, SCE pursued development of five combustion turbine peakerplants, four of which were placed online in August 2007 to help meet peak customer demands and othersystem requirements. In its cost recovery application for the four constructed peaker plants, SCE will revise

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the total recorded costs as of the end of 2008, to approximately $263 million. SCE also proposed to continuetracking the capital costs of a fifth peaker plant in the interim cost tracking mechanism approved by the CPUCand used during the construction period. Additionally, SCE proposed to file a separate cost recoveryapplication for the fifth peaker after it is installed or its final disposition is otherwise determined (see belowfor further discussion on the status of the fifth peaker plant). Several parties have filed protests or other filingsin response to SCE’s cost recovery application. SCE expects to fully recover its costs from these peakerplants, but cannot predict the outcome of regulatory proceedings. SCE expects a CPUC decision on its costrecovery application for the first four peaker plants in 2009.

SCE has continued to pursue the construction of the fifth peaker plant. As of December 31, 2008, SCE hasincurred capital costs of approximately $39 million for the fifth peaker, primarily for the purchase of themajor piece of capital equipment, the combustion turbine. The required development permit for the fifthpeaker plant was denied by the City of Oxnard in July 2007 and SCE appealed the denial to the CaliforniaCoastal Commission. The Commission heard SCE’s appeal on August 6, 2008, but did not reach a finaldecision. SCE expects the matter to be heard again by April 2009 but cannot predict the outcome of theappeal. SCE expects to fully recover its costs for the fifth peaker plant.

Procurement of Renewable Resources

California law requires SCE to increase its procurement of renewable resources by at least 1% of its annualretail electricity sales per year so that 20% of its annual electricity sales are procured from renewableresources by no later than December 31, 2010.

It is unlikely that SCE will have 20% of its annual electricity sales procured from renewable resources by2010. However, SCE may still meet the 20% target by utilizing the flexible compliance rules, such as bankingof past surplus and earmarking of future deliveries from executed contracts. SCE continues to engage inseveral renewable procurement activities including formal solicitations approved by the CPUC, bilateralnegotiations with individual projects and other initiatives.

Under current CPUC decisions, potential penalties for SCE’s inability to achieve its renewable procurementobjectives for any year will be considered by the CPUC in the context of the CPUC’s review of SCE’s annualcompliance filing. Under the CPUC’s current rules, the maximum penalty for inability to achieve renewableprocurement targets is $25 million per year. SCE does not believe it will be assessed penalties for 2008 or theprior years and cannot predict whether it will be assessed penalties for future years.

Mohave Generating Station and Related Proceedings

Mohave obtained all of its coal supply from the Black Mesa Mine in northeast Arizona, located on lands ofthe Tribes. This coal was delivered from the mine to Mohave by means of a coal slurry pipeline, whichrequired water from wells located on lands belonging to the Tribes in the mine vicinity. Uncertainty over post-2005 coal and water supply prevented SCE and other Mohave co-owners from making approximately$1.1 billion in Mohave-related investments (SCE’s share is $605 million), including the installation ofenhanced pollution-control equipment required by a 1999 air-quality consent decree in order for Mohave tooperate beyond 2005. Accordingly, the plant ceased operations, as scheduled, on December 31, 2005,consistent with the provisions of the consent decree, and there are no plans for the co-owners to return theplant to service.

The co-owners are continuing to evaluate the range of options for disposition of the plant, which conceivablycould include, among other potential options, sale of the plant to a power plant operator, decommissioning ofthe plant and sale of the property, decommissioning and apportionment of the land among the owners, ordeveloping in conjunction with some or all of the co-owners a renewable energy facility at the property.

SCE believed it was in full compliance with CPUC requirements and as of December 31, 2008, SCE had aMohave net regulatory asset of approximately $54 million representing its net unamortized coal plant

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investment, partially offset by revenue collected for future removal costs. Based on a CPUC decision, SCE isallowed to continue to earn its authorized rate of return on the Mohave investment and receive rate recoveryfor amortization, costs of removal, and operating and maintenance expenses, subject to balancing accounttreatment. On October 5, 2006, SCE submitted a formal notification to the CPUC regarding the out-of-servicestatus of Mohave. The CPUC may institute an investigation to determine whether to reduce SCE’s rates inlight of Mohave’s changed status. At this time, SCE does not anticipate that the CPUC will order a ratereduction. However, SCE cannot predict the outcome of any future CPUC action.

ISO Disputed Charges

On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities ofAnaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization ofcertain transmission service related charges. The potential cost to SCE of the FERC order, net of amountsSCE expects to receive through the PX, SCE’s scheduling coordinator at the pertinent time, is estimated to beapproximately $20 million to $25 million, including interest. The order has been the subject of continuinglegal proceedings since it was issued. SCE believes that the most recent substantive order FERC has issued inthe proceedings correctly allocates responsibility for these ISO charges. However, SCE cannot predict the finaloutcome of the rehearing. If a subsequent regulatory decision changes the allocation of responsibility for thesecharges, and SCE is required to pay these charges as a transmission owner, SCE may seek recovery in itsreliability service rates. SCE cannot predict whether recovery of these charges in its reliability service rateswould be permitted.

Market Redesign and Technology Upgrade

In early 2006, the ISO began a program to redesign and upgrade the wholesale energy market across ISO’scontrolled grid, known as the MRTU. The programs under the MRTU initiative are designed to implementmarket improvements to assure grid reliability, more efficient and cost-effective use of resources, and to createtechnology upgrades that would strengthen the entire ISO computer system. The CAISO has targeted theMRTU market to be operational March 31, 2009, subject to certain conditions, and filed a readinessapplication with the FERC in January 2009. See “SCE: Market Risk Exposures — Commodity Price Risk —Market Redesign and Technology Upgrade” for further discussion.

SCE: OTHER DEVELOPMENTS

Palo Verde Nuclear Generating Station Inspection

The NRC held three special inspections of Palo Verde, between March 2005 and February 2007. Thecombination of the results of the first and third special inspections caused the NRC to undertake an additionaloversight inspection of Palo Verde. This additional inspection, known as a supplemental inspection, wascompleted in December 2007. In addition, Palo Verde was required to take additional corrective actions basedon the outcome of completed surveys of its plant personnel and self-assessments of its programs andprocedures. The NRC and APS defined and agreed to inspection and survey corrective actions that the NRCembodied in a Confirmatory Action Letter, which was issued in February 2008. APS is presently on track tocomplete the corrective actions required to close the Confirmatory Action Letter by mid-2009. Palo Verdeoperation and maintenance costs (including overhead) increased in 2007 by approximately $7 million from2006. SCE estimates that operation and maintenance costs will increase by approximately $23 million (in2007 dollars) over the two year period 2008 – 2009, from 2007 recorded costs including overhead costs. In the2009 GRC, SCE requested recovery of, and two-way balancing account treatment for, Palo Verde operationand maintenance expenses including costs associated with these corrective actions. If approved, this wouldprovide for recovery of these costs over the three-year GRC cycle (see “SCE: Regulatory Matters — CurrentRegulatory Developments — 2009 General Rate Case Proceeding” above for more information).

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Navajo Nation Litigation

The Navajo Nation filed a complaint in June 1999 in the District Court against SCE, among other defendants,arising out of the coal supply agreement for Mohave. The complaint asserts claims for, among other things,violations of the federal RICO statute, interference with fiduciary duties and contractual relations, fraudulentmisrepresentations by nondisclosure, and various contract-related claims. The complaint claims that thedefendants’ actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coalsupplied to Mohave. The complaint seeks damages of not less than $600 million, trebling of that amount, andpunitive damages of not less than $1 billion. In March 2001, the Hopi Tribe was permitted to intervene as anadditional plaintiff but has not yet identified a specific amount of damages claimed. The case was stayed atthe request of the parties in October 2004, but was reinstated to the active calendar in March 2008.

A related case against the U.S. Government is presently before the U.S. Supreme Court. The outcome of thatcase could affect the Navajo Nation’s pursuit of claims against SCE. A decision from the U.S. Supreme Courtis expected in mid-2009.

SCE cannot predict the outcome of the Tribe’s complaints against SCE or the ultimate impact on thesecomplaints of the on-going litigation by the Navajo Nation against the U.S. Government in the related case.

Spent Nuclear Fuel

Under federal law, the DOE is responsible for the selection and construction of a facility for the permanentdisposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its contractualobligation to begin acceptance of spent nuclear fuel by January 31, 1998. It is not certain when the DOE willbegin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended delays by theDOE have led to the construction of costly alternatives and associated siting and environmental issues. SCEhas paid the DOE the required one-time fee applicable to nuclear generation at San Onofre (approximately$24 million, plus interest). SCE has also been paying a required quarterly fee equal to 0.1¢ per-kWh ofnuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating agent, filed acomplaint against the DOE in the United States Court of Federal Claims seeking damages for the DOE’sfailure to meet its obligation to begin accepting spent nuclear fuel from San Onofre.

SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Suchinterim storage for San Onofre is on-site.

APS, as operating agent, has primary responsibility for the interim storage of spent nuclear fuel at Palo Verde.Palo Verde plans to add storage capacity incrementally to maintain full core off-load capability for all threeunits. In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde hasconstructed an independent spent fuel storage facility.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to the amount of available financialprotection, which is currently approximately $12.5 billion. SCE and other owners of San Onofre and PaloVerde have purchased the maximum private primary insurance available ($300 million). The balance iscovered by the industry’s retrospective rating plan that uses deferred premium charges to every reactorlicensee if a nuclear incident at any licensed reactor in the United States results in claims and/or costs whichexceed the primary insurance at that plant site.

Federal regulations require this secondary level of financial protection. The NRC exempted San Onofre Unit 1from this secondary level, effective June 1994. Beginning October 29, 2008, the maximum deferred premiumfor each nuclear incident is approximately $118 million per reactor, but not more than approximately$18 million per reactor may be charged in any one year for each incident. The maximum deferred premiumper reactor and the yearly assessment per reactor for each nuclear incident is adjusted for inflation at leastonce every five years. The most recent inflation adjustment took effect on October 29, 2008. Based on its

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ownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclearincident. However, it would have to pay no more than approximately $35 million per incident in any one year.Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and aresubject to adjustment for inflation. If the public liability limit above is insufficient, federal law contemplatesthat additional funds may be appropriated by Congress. This could include an additional assessment on alllicensed reactor operators as a measure for raising further electric utility revenue.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofreand Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 millionalso has been purchased in amounts greater than federal requirements. Additional insurance covers part ofreplacement power expenses during an accident-related nuclear unit outage. A mutual insurance companyowned by utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by thearrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessedretrospective premium adjustments of up to approximately $45 million per year. Insurance premiums arecharged to operating expense.

Wildfire Insurance Issues

Recent, severe wildfires in California have given rise to very large damage claims against California utilities.Additionally, California law includes a doctrine of inverse condemnation that imposes strict liability (includingliability for a claimant’s attorneys’ fees) for fire damage caused to private property by SCE’s electric facilitiesthat serve the public. SCE currently is insured for such liabilities up to a limit of $650 million (with a$2 million self-insured retention) until September 2009. The strict liability standard and the apparent risingtrend in wildfire occurrences and intensity may affect SCE’s ability to obtain comparable insurance levels atcomparable cost in the future, and there can be no assurance that SCE would be allowed to recover incustomer rates the increased cost of such insurance or the cost of any uninsured losses. In addition, the CPUCinvestigates fires that may have been caused by a utility’s facilities, and, if violations of CPUC regulations arefound, the CPUC may penalize the utility.


Edison International files its federal income tax returns on a consolidated basis and files on a combined basisin California and certain other states. SCE is included in the consolidated federal and state combined incometax returns. See “Other Developments — Federal and State Income Taxes” for further discussion of thesematters.

SCE: LIQUIDITY

Overview

As of December 31, 2008, SCE had cash and equivalents of $1.6 billion ($89 million of which was held bySCE’s consolidated VIEs). As a reaction to significant disruption in the credit and capital markets, SCEborrowed against its credit facility and issued bonds in October 2008 to ensure the availability of funds tomeet its future cash requirements. The proceeds were invested in U.S. treasury bills and U.S. treasury andgovernment agency money market funds. This credit line draw is recorded as short-term debt, as it is expectedto be re-paid by year-end 2009.

In March 2008, SCE amended its existing $2.5 billion credit facility, extending the maturity to February 2013while retaining existing borrowing costs as specified in the facility. The amendment also provides fourextension options which, if all exercised, and agreed to by the lenders, will result in a final termination inFebruary 2017. During February 2009, SCE has been negotiating with several banks to potentially increase itsliquidity facilities by an additional $500 million. The consummation of such negotiations is subject to theavailability of additional bank credit capacity on commercially feasible terms. Such liquidity would be used toaddress potential requirements of SCE’s ongoing procurement-related needs.

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A subsidiary of Lehman Brothers Holdings, Lehman Brothers Bank, FSB, is one of the lenders in SCE’s creditagreement representing a total commitment of $106 million. Lehman Brothers Bank, FSB, had funded$25 million of a borrowing request during the second quarter of 2008. On September 15, 2008, LehmanBrothers Holdings filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Lehman Brothers Bank,FSB, declined requests for funding of approximately $57 million during the second half of 2008.

The following table summarizes the status of the SCE credit facility at December 31, 2008:

In millions SCE

Commitment $ 2,500Less: Unfunded commitment from Lehman Brothers subsidiary (81)

2,419Outstanding borrowings (1,893)Outstanding letters of credit (141)

Amount available $ 385

As of December 31, 2008, SCE’s long-term debt, including current maturities of long-term debt, was$6.4 billion. In October 2008, SCE issued $500 million of 5.75% first and refunding mortgage bonds due in2014.

SCE’s estimated cash outflows during the 12-month period following December 31, 2008 are expected toconsist of:

• Projected capital expenditures primarily to replace and expand distribution and transmission infrastructureand construct and replace major components of generation assets (see “— Capital Expenditures” below);

• Fuel and procurement-related costs (see “SCE: Regulatory Matters — Current Regulatory Developments —Energy Resource Recovery Account Proceedings”), including collateral requirements (see “— Margin andCollateral Deposits”);

• In December 2008 the Board of Directors of SCE declared a $100 million dividend to Edison Internationalwhich was paid in January 2009. As a result of SCE’s cash requirements, including its capital expendituresplan, SCE does not expect to declare additional dividends to Edison International in 2009;

• Maturity and interest payments on short- and long-term debt outstanding;

• General operating expenses; and

• Pension and PBOP trust contributions (see “— Pension and PBOP trusts” below).

As discussed above, SCE expects to meet its 2009 continuing obligations, including cash outflows foroperating expenses and power-procurement, through cash and equivalents on hand and operating cash flows.Projected 2009 capital expenditures are expected to be financed through cash and equivalents on hand,operating cash flows and incremental capital market financings of debt and preferred equity. SCE expects thatit would also be able to draw on the remaining availability of its credit facility and access capital markets ifadditional funding and liquidity is necessary to meet the estimated operating and capital requirements, butgiven current market conditions there can be no assurance of such credit and capital availability.

On February 13, 2008, President Bush signed the Economic Stimulus Act of 2008 (2008 Stimulus Act). The2008 Stimulus Act includes a provision that provides accelerated bonus depreciation for certain capitalexpenditures incurred during 2008. Edison International expects that certain capital expenditures incurred bySCE during 2008 will qualify for this accelerated bonus depreciation, which would provide additional cashflow benefits estimated to be approximately $110 million for the 2008 tax return. On February 17, 2009,President Obama signed the American Recovery and Reinvestment Act of 2009 which extended theaccelerated bonus depreciation provision through the end of 2009. Edison International expects that certaincapital expenditures incurred by SCE during 2009 will qualify for this accelerated bonus depreciation.

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SCE’s liquidity may be affected by, among other things, matters described in “SCE: Regulatory Matters” and“Commitments, Guarantees and Indemnities.”

Capital Expenditures

SCE has planned capital expenditures to replace and expand its distribution and transmission infrastructure,and to construct and replace generation assets. As previously discussed, the CPUC has issued anAdministrative Law Judge’s proposed decision, as well as a revised alternate proposed decision on SCE’s 2009GRC. The two proposed decisions provide for different levels of capital expenditures. Based on the revisedalternate proposed decision and reflecting a level of variability (discussed below), SCE’s 2009 through 2013capital investment plan includes capital spending in the range of $17.1 billion to $21 billion. TheAdministrative Law Judge’s proposed decision, if adopted, would further reduce the range of capital spendingby approximately $2.8 billion related to a $2.0 billion modeling error which authorizes a specified level ofcapital expenditures, but does not provide the revenue requirement to recover a portion of these capitalexpenditures beginning in 2010 and an $800 million reduction in the level of capital expenditures. Recovery ofthe CPUC jurisdictional 2009 through 2011 planned expenditures primarily is subject to CPUC approval inSCE’s 2009 GRC application. Recovery of certain other projects included in the 2009 through 2011investment plan has been approved or will be requested and approved through other CPUC-authorizedmechanisms on a project-by-project basis. These projects include, among others, SCE’s SmartConnectadvanced metering infrastructure project, the San Onofre steam generator replacement project, and the solarphotovoltaic program. SCE plans total investments for 2009 through 2013 to be $1.2 billion, $450 million and$880 million, for each of these projects, respectively. SCE’s GRC related expenditures for 2012 and 2013 aresubject to future approval. Recovery of the 2009 through 2013 planned transmission expenditures for FERC-jurisdictional projects have been requested in the 2009 FERC Rate Case proceeding, or will be requested infuture transmission filings with the FERC.

SCE’s 2008 capital expenditures (including accruals) were $2.4 billion related to its 2008 capital plan. SCE’s2008 capital expenditures were less than the forecast for 2008 of $2.9 billion, primarily due to delays intransmission investments as well as other timing delays. Developments in the financial markets, regulatorydecisions, and economic conditions in the U.S. may also alter SCE’s future capital expenditures plans. See“Edison International: Management Overview — Areas of Business Focus — Financial Markets and EconomicConditions” for further discussion. The completion of the projects, the timing of expenditures, and theassociated recovery may be affected by permitting requirements and delays, construction delays, availability oflabor, equipment and materials, financing, legal and regulatory developments, weather and other unforeseenconditions. The estimated capital expenditures for the next five years may vary from SCE’s current forecast. IfSCE assumes the same level of variability to forecast experienced in 2008 (approximately 18%), SCE’s 2009forecast would vary in the range of $2.9 billion to $3.6 billion. If the Administrative Law Judge’s proposeddecision is adopted, the 2009 forecast would be reduced by approximately $800 million resulting from a$600 million modeling error and a $200 million reduction in the level of capital expenditures, both discussedabove.

Included in SCE’s capital investment plan are projected environmental capital expenditures of $476 million in2009 and approximately $2.1 billion for the period 2010 through 2013. The projected environmental capitalexpenditures are mainly for undergrounding certain transmission and distribution lines at SCE.

Solar Photovoltaic Program

On March 27, 2008, SCE filed an application with the CPUC to implement its Solar Photovoltaic (PV)Program to develop up to 250 MW of utility-owned Solar PV generating facilities ranging in size from 1 to2 MW each on commercial and industrial rooftop space in SCE’s service territory. Subject to CPUC approval,the capital expenditures will be eligible to be included in SCE’s earning asset base if the actual costs of theprogram are equal to or lower than the reasonableness threshold amount of $963 million in nominal dollars.SCE also proposes to apply a CPUC-established 100 basis point incentive adder to SCE’s allowed rate of

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return on rate base on the project. In September 2008, the CPUC granted SCE’s request to track costs spent onprojects up to $25 million incurred prior to the receipt of the CPUC’s final decision in a memorandumaccount for potential future recovery. SCE has spent $12 million as of December 31, 2008. SCE completed itsfirst 2 MW project in December 2008, and expects to continue to move forward with two other projects inadvance of the final CPUC decision subject to the authorized tracking account mechanism. In September2008, several parties filed testimony opposing SCE’s Solar PV program application. Evidentiary hearings tookplace in November 2008 and a final decision is expected in March 2009. SCE cannot predict the finaloutcome of this proceeding.

EdisonSmartConnecttm

SCE’s EdisonSmartConnecttm project involves installing state-of-the-art “smart” meters in approximately5.3 million households and small businesses through its service territory. The development of this advancedmetering infrastructure is expected to be accomplished in three phases: the initial design phase to develop thenew generation of advanced metering systems (Phase I), which was completed in 2006; the pre-deploymentphase (Phase II) to field test and select EdisonSmartConnecttm technologies, select the deployment vendor andfinalize the EdisonSmartConnecttm business case for full deployment, which was completed in December2007; and the final deployment phase (Phase III), to deploy meters to all residential and small businesscustomers under 200 kW over a five-year period. SCE applied to the CPUC in July 2007 to request authorityto deploy the program and began deployment activities in 2008. In March 2008, SCE reached a full settlementof the Phase III issues with the DRA and in September 2008, the CPUC approved the settlement, authorizingSCE to recover $1.63 billion in ratepayer funding for the Phase III deployment of EdisonSmartConnecttm.SCE expects to begin deployment of meters in 2009, and anticipates completion of the deployment in 2012.The total cost for this project, including Phase II pre-deployment, is estimated to be $1.7 billion of which$1.25 billion is estimated to be capitalized and included in utility rate base. The remaining book value forSCE’s existing meters at December 31, 2008 is $398 million. SCE expects to recover the remaining bookvalue of the existing meters, with a return, over their remaining lives through its 2009 GRC application.

Pension and PBOP Trusts

Volatile market conditions have affected the value of SCE’s trusts established to fund its future long-termpension benefits and other postretirement benefits. The fair value of the investments (reflecting investmentperformance, contributions and benefit payments) within the pension and PBOP plan trusts declined 35% and33%, respectively, during 2008. These benefit plan assets and related obligations are remeasured annuallyusing a December 31 measurement date. The plans’ funded status is recorded on the balance sheet inaccordance with SFAS No. 158. Due to the reductions in the value of plan assets, the pension and PBOP planswere underfunded $937 million and $1 billion at December 31, 2008, respectively. Forecast expense in 2009and contributions for the 2009 plan year are expected to increase by approximately $150 million. SCE isauthorized to recover these costs through customer rates, therefore recognition of the funded status of SCE’splans is offset by regulatory assets of $1.9 billion. In the 2009 GRC, SCE requested continued balancingaccount treatment for amounts contributed to these trusts and requested that these amounts be collectedannually (see “SCE: Regulatory Matters — Current Regulatory Developments — 2009 General Rate CaseProceeding” for further discussion). In response to the volatile market conditions, the trusts’ investmentcommittees have implemented interim lower equity allocation targets and continue to assess the long-termasset allocation strategies. The Pension Protection Act of 2006 established minimum funding standards andrestricts plan payouts if underfunded by more than 20%, limiting provisions for lump-sum distributions andadopting amendments that increase plan liabilities.

Nuclear Decommissioning Trusts

Volatile market conditions have also affected the value of SCE’s trusts established to fund nucleardecommissioning obligations. SCE is collecting in rates amounts for the future costs of removal of its nuclear

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assets, and has placed those amounts in independent trusts. Funds collected, together with accumulatedearnings, will be utilized solely for decommissioning.

Nuclear decommissioning costs are recovered in utility rates. These costs are expected to be funded fromindependent decommissioning trusts, which currently receive contributions of approximately $46 million peryear. Contributions to the decommissioning trusts are reviewed every three years by the CPUC. The next filingis in April 2009 for contribution changes in 2011. The significant decrease recently experienced in the nucleardecommissioning trust assets, is expected, absent a market recovery, to impact the CPUC establishedcontributions for 2011. In response to the volatile market conditions, the trusts’ investment committees haveimplemented interim lower equity allocation targets and continue to assess the long-term asset allocationstrategies. See “Critical Accounting Estimates and Policies — Nuclear Decommissioning” for furtherinformation.

Trust investments (at fair value) are as follows:

In millions Maturity DatesDecember 31,

2008December 31,

2007

Municipal bonds 2009 – 2044 $ 629 $ 561Stocks – 1,308 1,968United States government issues 2009 – 2049 304 552Corporate bonds 2009 – 2047 260 241Short-term investments, primarily cash equivalents 2009 23 56

Total $ 2,524 $ 3,378

Note: Maturity dates as of December 31, 2008.

The following table sets forth a summary of changes in the fair value of the trust for December 31, 2008:

In millionsDecember 31,

2008

Balance at beginning of period $ 3,378Realized losses – net (65)Unrealized losses – net (545)Other-than-temporary impairment (317)Earnings and other 73

Balance at December 31, 2008 $ 2,524

Credit Ratings

At December 31, 2008, SCE’s credit ratings were as follows:

Moody’s Rating S&P Rating Fitch Rating

Long-term senior secured debt A2 A A+Short-term (commercial paper) P-2 A-2 F-1

The above SCE credit ratings have remained unchanged since year-end 2007. SCE cannot provide assurancethat its current credit ratings will remain in effect for any given period of time or that one or more of theseratings will not be changed. These credit ratings are not recommendations to buy, sell or hold its securities andmay be revised at any time by a rating agency.

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Dividend Restrictions and Debt Covenants

The CPUC regulates SCE’s capital structure and limits the dividends it may pay Edison International. InSCE’s most recent cost of capital proceeding, the CPUC sets an authorized capital structure for SCE whichincluded a common equity component of 48%. SCE may make distributions to Edison International as long asthe common equity component of SCE’s capital structure remains at or above the authorized level on a13-month weighted average basis of 48%. At December 31, 2008, SCE’s 13-month weighted-average commonequity component of total capitalization was 50.6% resulting in the capacity to pay $345 million in additionaldividends.

SCE has a debt covenant in its credit facility that requires a debt to total capitalization ratio of less than orequal to 0.65 to 1 to be met. At December 31, 2008, SCE’s debt to total capitalization ratio was 0.53 to 1.

Margin and Collateral Deposits

SCE has entered into certain margining agreements for power and natural gas trading activities in support ofits procurement plan as approved by the CPUC. SCE’s margin deposit requirements under these agreementscan vary depending upon the level of unsecured credit extended by counterparties and brokers, changes inmarket prices relative to contractual commitments, and other factors. Future collateral requirements may behigher (or lower) than collateral requirements at December 31, 2008, due to the addition of incremental powerand energy procurement contracts with margining agreements, if any, and the impact of changes in wholesalepower and natural gas prices on SCE’s contractual obligations.

Certain requirements to post cash and/or collateral (primarily for changes in fair value and accounts payableson delivered energy transactions) would be triggered if SCE’s credit ratings were downgraded to belowinvestment grade, as indicated in the table below.

In millions

Collateral posted as of December 31, 2008(1) $ 230Incremental collateral requirements resulting from a potential downgrade of SCE’s

credit rating to below investment grade 186

Total posted and potential collateral requirements(2) $ 416

(1) Collateral posted consisted of $72 million which were offset against net derivative liabilitiesin accordance with the implementation of FIN 39-1, and $158 million provided tocounterparties and other brokers (consisting of $17 million in cash reflected in “Margin andcollateral deposits” on the consolidated balance sheets and $141 million in letters of credit).

(2) Total posted and potential collateral requirements may increase by an additional$124 million, based on SCE’s forward position as of December 31, 2008, due to adversemarket price movements over the remaining life of the existing contracts using a 95%confidence level.

SCE’s incremental collateral requirements are expected to be met from liquidity available from cash on handand available capacity under SCE’s $2.5 billion credit facility, discussed above.

SCE: MARKET RISK EXPOSURES

SCE’s primary market risks include fluctuations in interest rates, commodity prices and volumes, andcounterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations incommodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are notexpected to affect earnings due to expected recovery through regulatory mechanisms. SCE uses derivativefinancial instruments, as appropriate, to manage its market risks.

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Interest Rate Risk

SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities usedfor liquidity purposes, to fund business operations and to finance capital expenditures. The nature and amountof SCE’s long-term and short-term debt can be expected to vary as a result of future business requirements,market conditions and other factors. In addition, SCE’s authorized return on common equity (11.5% for 2009and 2008 and 11.6% for 2007), which is established in SCE’s cost of capital proceeding, is set on the basis offorecasts of interest rates and other factors. Variances in actual financing costs compared to authorizedfinancing costs either positively or negatively impact earnings. See “SCE: Regulatory Matters — Base Rates”for further discussion on SCE’s recoverability of financing costs.

At December 31, 2008, SCE did not believe that its short-term debt was subject to interest rate risk, due to thefair market value being approximately equal to the carrying value. At December 31, 2008, the fair marketvalue of SCE’s long-term debt (including long-term debt due within one year) was $6.7 billion, compared to acarrying value of $6.4 billion. A 10% increase in market interest rates would have resulted in a $336 milliondecrease in the fair market value of SCE’s long-term debt. A 10% decrease in market interest rates wouldhave resulted in a $368 million increase in the fair market value of SCE’s long-term debt.

In July 2007, SCE entered into interest rate-locks to mitigate interest rate risk associated with futurefinancings. Due to declining interest rates in late 2007, at December 31, 2007, these interest rate locks hadunrealized losses of $33 million. In January and February 2008, SCE settled these interest rate-locks resultingin realized losses of $33 million. A related regulatory asset was recorded in this amount and SCE willamortize and recover this amount as interest expense associated with its series 2008A and 2008B financingsissued in January and August 2008.

Commodity Price Risk

Introduction

SCE is exposed to commodity price risk from its purchases of additional capacity and ancillary services tomeet peak energy requirements and from exposure to natural gas prices that affect costs associated with powerpurchased from QFs, fuel tolling arrangements, and its own gas-fired generation, including SCE’sMountainview plant. Contract energy prices for most nonrenewable QFs are based in large part on the monthlysouthern California border price of natural gas. In addition to the QF contracts, SCE has power contracts inwhich SCE has agreed to provide the natural gas needed for generation under those power contracts, which arereferred to as tolling arrangements. In addition to SCE’s Mountainview and peaker plants, approximately 46%of SCE’s power purchase requirements are subject to natural gas price volatility.

The CPUC has established resource adequacy requirements which require SCE to acquire and demonstrateenough generating capacity in its portfolio for a planning reserve margin of 15 – 17% above its peak load asforecast for an average year (see “SCE: Regulatory Matters — Current Regulatory Developments — ResourceAdequacy Requirements”). The establishment of a sufficient planning reserve margin mitigates, to someextent, exposure to commodity price risk for spot market purchases.

SCE’s purchased-power costs and gas expenses, as well as related hedging costs, are recovered through theERRA. To the extent SCE conducts its power and gas procurement activities in accordance with its CPUC-authorized procurement plan, California statute (Assembly Bill 57) establishes that SCE is entitled to full costrecovery. As a result of these regulatory mechanisms, changes in energy prices may impact SCE’s cash flowsbut are not expected to affect earnings. Certain SCE activities, such as contract administration, SCE’s duties asthe CDWR’s limited agent for allocated CDWR contracts, and portfolio dispatch are reviewed annually by theCPUC for reasonableness. The CPUC has currently established a maximum disallowance cap of $37 millionfor these activities.

In accordance with CPUC decisions, SCE, as the CDWR’s limited agent, performs certain services for CDWRcontracts allocated to SCE by the CPUC, including arranging for natural gas supply. Financial and legal

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responsibility for the allocated contracts remains with the CDWR. The CDWR, through coordination withSCE, has hedged a portion of its expected natural gas requirements for the gas tolling contracts allocated toSCE. Increases in gas prices over time, however, will increase the CDWR’s gas costs. California state lawpermits the CDWR to recover its actual costs through rates established by the CPUC. This would affect ratescharged to SCE’s customers, but would not affect SCE’s earnings or cash flows. As discussed under theheading, “SCE: Regulatory Matters — Current Regulatory Developments — Impact of Regulatory Matters onCustomer Rates,” if the existing CDWR power contracts, which have related natural gas supply contracts, arenovated or replaced and SCE becomes a party to such contracts, SCE may have additional exposure to a risein gas prices. SCE is currently unable to predict which or how many existing CDWR contracts will be novatedor replaced. However, due to the expected recovery through regulatory mechanisms these power procurementexpenses are not expected to affect earnings.

Natural Gas and Electricity Price Risk

SCE has an active hedging program in place to minimize ratepayer exposure to spot-market price spikes;however, to the extent that SCE does not mitigate the exposure to commodity price risk, the unhedged portionis subject to the risks and benefits of spot-market price movements, which are ultimately passed-through toratepayers.

To mitigate SCE’s exposure to spot-market prices, SCE enters into energy options, tolling arrangements,forward physical contracts and transmission congestion rights (FTRs and CRRs). SCE also enters intocontracts for power and gas options, as well as swaps and futures, in order to mitigate its exposure toincreases in natural gas and electricity pricing. These transactions are pre-approved by the CPUC or executedin compliance with CPUC-approved procurement plans.

SCE records its derivative instruments on its consolidated balance sheets at fair value unless they meet thedefinition of a normal purchase or sale. The derivative instrument fair values are marked to market at eachreporting period. Any fair value changes are expected to be recovered from or refunded to customers throughregulatory mechanisms and therefore, SCE’s fair value changes have no impact on purchased-power expenseor earnings. Hedge accounting is not used for these transactions due to this regulatory accounting treatment.

The following table summarizes the fair values of outstanding derivative financial instruments used at SCE tomitigate its exposure to spot market prices:

In millions Assets Liabilities Assets Liabilities

December 31, 2008 December 31, 2007

Electricity options, swaps and forward arrangements $ 7 $ 15 $ 13 $ 57Gas options, swaps and forward arrangements 80 305 46 22Firm transmission rights and congestion revenue

rights(1) 81 — 22 —Tolling arrangements(2) 63 647 — —Netting and collateral — (72) — (2)

Total $ 231 $ 895 $ 81 $ 77

(1) During the first quarter of 2008, the ISO held an auction for firm transmission rights. SCEparticipated in the ISO auction and paid $62 million to secure firm transmission rights for theperiod April 2008 through March 2009. The firm transmission rights will be replaced with CRRsin the MRTU environment. See “— Market Redesign and Technology Upgrade” below for furtherdiscussion. SCE recognized the firm transmission rights at fair value. SCE anticipates amountspaid for firm transmission rights that will no longer be valid in the MRTU environment will berefunded to SCE and has recognized this amount as a receivable from the ISO.

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In September 2007 and November 2008, the CAISO allocated CRRs for the period April 2009through December 2017 based on its expected generation flows. In addition, during the fourthquarter of 2008 SCE participated in a CAISO auction for the procurement of additional CRRs.The CRRs meet the definition of a derivative under SFAS No. 133. In accordance withSFAS No. 157, SCE recognized the CRRs at a $73 million fair value for the short term portion.SCE recorded liquidity reserves against the long-term CRRs fair values since there were noquoted long-term market prices for the CRRs and insufficient evidence of long-term marketprices.

(2) In compliance with a CPUC mandate, SCE held an open, competitive solicitation that producedagreements with different project developers who have agreed to construct new, state-of-the-artSouthern California generating resources. SCE has entered into a number of contracts, of whichfive received regulatory approval in the fourth quarter of 2008 and are recorded as financialderivatives. The contracts provide for fixed capacity payments as well as fixed pricing for energydelivered. The mark to market unrealized loss associated with the agreements are due to thedecrease in forward gas market prices.

A 10% increase in electricity prices at December 31, 2008 would increase the fair value of electricity options,swaps and forward arrangements by approximately $39 million; a 10% decrease in electricity prices atDecember 31, 2008, would decrease the fair value by approximately $38 million. A 10% increase inelectricity prices at December 31, 2008 would increase the fair value of tolling arrangements by approximately$293 million; a 10% decrease in electricity prices at December 31, 2008, would decrease the fair value byapproximately $96 million. A 10% increase in gas prices at December 31, 2008 would increase the fair valueof gas options, swaps and forward arrangements by approximately $101 million; a 10% decrease in gas pricesat December 31, 2008, would decrease the fair value by approximately $112 million. A 10% increase inelectricity prices at December 31, 2008 would decrease the fair value of firm transmission rights andcongestion revenue rights by approximately $3 million; a 10% decrease in electricity prices at December 31,2008, would decrease the fair value by approximately $3 million.

SCE’s realized gains and losses arising from derivative instruments are reflected in purchased-power expenseand are recovered through the ERRA mechanism. Unrealized gains and losses have no impact on purchased-power expense due to regulatory mechanisms. As a result, realized and unrealized gains and losses do notaffect earnings, but may temporarily affect cash flows. Realized losses on economic hedging were $60 millionin 2008, $132 million in 2007, and $339 million in 2006. Unrealized (gains) losses on economic hedging were$638 million in 2008, $(94) million in 2007, and $237 million in 2006. Changes in realized and unrealizedgains and losses on economic hedging activities were primarily due to significant decreases in forward naturalgas prices in 2008 compared to 2007. Changes in realized and unrealized gains and losses on economichedging activities in 2007 compared to 2006 were primarily due to changes in SCE’s gas hedge portfolio mixas well as an increase in the natural gas futures market in 2007.

Market Redesign and Technology Upgrade

As previously discussed in “SCE: Regulatory Matters — Current Regulatory Developments — MarketRedesign and Technology Upgrade,” the CAISO has targeted the MRTU market to be operational onMarch 31, 2009, subject to certain conditions. The MRTU market design allows the CAISO to conduct a day-ahead market that combines energy, ancillary services and congestion management. By starting this process inthe day-ahead time frame, there is less reliance on the more volatile hour-ahead and real-time markets.

The new MRTU market will provide day-ahead and real-time markets using Nodal Locational Marginal Prices,eliminating the current zonal environment. The impact of MRTU on SCE is primarily driven by this transitionfrom zonal to nodal prices as well as the introduction of a central day-ahead energy market operated byCAISO. The nodal prices will provide enhanced transparency of market prices throughout the CAISO controlarea, but it may also make forecasting prices more challenging due to the complexity and data intensity thatCAISO uses to calculate energy prices. The introduction of the day-ahead market (known as the Integrated

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Forward Market or IFM) will change the way SCE manages its portfolio: rather than matching supply anddemand resources before submitting energy schedules to CAISO as is done today, under MRTU SCE will needto bid its generation and load requirements into the IFM. In essence, SCE will sell its generation from itsutility-owned generation assets and existing power procurement contracts through IFM and buy its loadrequirements from IFM. SCE will bid its generation at nodes near the source of the generation, but will takedelivery at nodes throughout SCE’s service territory. Congestion may occur due to transmission constraintsresulting in transmission congestion charges and differences in Nodal Locational Marginal Prices at thevarious nodes. The CAISO created a commodity, CRRs, which entitles the holder to receive (or pay) the valueof transmission congestion between specific nodes, acting as an economic hedge against transmissioncongestion charges.

MRTU also introduces a new CAISO market called Residual Unit Commitment (RUC). This market enablesCAISO to procure additional generation capacity (in addition to what cleared in the day-ahead market) to meetthe CAISO-estimated load. SCE is required to participate in the RUC market with its Resource Adequacyunits and may participate with other units as well.

The CAISO market that exists today for ancillary services and real-time supplemental energy will continue inMRTU, but will be adapted to the nodal pricing model and SCE will continue to participate in these markets.

Due to established regulatory mechanisms SCE’s fair value changes have no impact on purchased-powerexpense or earnings.

Credit Risk

As part of SCE’s procurement activities, SCE contracts with a number of utilities, energy companies, financialinstitutions, and other companies, collectively referred to as counterparties. If a counterparty were to defaulton its contractual obligations, SCE could be exposed to potentially volatile spot markets for buyingreplacement power or selling excess power. In addition, SCE would be exposed to the risk of non-payment ofaccounts receivable, primarily related to sales of excess energy and realized gains on derivative instruments.

To manage credit risk, SCE looks at the risk of a potential default by counterparties. Credit risk is measuredby the loss that would be incurred if counterparties failed to perform pursuant to the terms of their contractualobligations. SCE measures, monitors and mitigates credit risk to the extent possible. SCE manages the creditrisk on the portfolio based on credit ratings using published ratings of counterparties and other publiclydisclosed information, such as financial statements, regulatory filings, and press releases, to guide it in theprocess of setting credit levels, risk limits and contractual arrangements, including master netting agreements.SCE’s risk management committee regularly reviews and evaluates procurement credit exposure and approvescredit limits for transacting with counterparties. Despite this, there can be no assurance that these efforts willbe wholly successful in mitigating credit risk or that collateral pledged will be adequate. However, all of thecontracts that SCE has entered into with counterparties are either entered into under SCE’s short-term or long-term procurement plan which has been approved by the CPUC, or the contracts are approved by the CPUCbefore becoming effective. As a result of regulatory recovery mechanisms, losses from non-performance arenot expected to affect earnings, but may temporarily affect cash flows. SCE anticipates future delivery ofenergy by counterparties, but given the current market condition, SCE cannot predict whether thecounterparties will be able to continue operations and deliver energy under the contractual agreements.

The credit risk exposure from counterparties for power and gas trading activities is measured as the sum of netaccounts receivable (accounts receivable less accounts payable) and the current fair value of net derivativeassets reflected on the balance sheet. SCE enters into master agreements which typically provide for a right ofsetoff. Accordingly, SCE’s credit risk exposure from counterparties is based on a net exposure under these

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arrangements. At December 31, 2008, the amount of balance sheet exposure as described above, broken downby the credit ratings of SCE’s counterparties, was as follows:

In millions Exposure(2) Collateral Net Exposure

December 31, 2008

S&P Credit Rating(1)

A or higher $ 73 $ 3 $ 70A- 81 (1) 82BBB+ 5 — 5BBB — — —BBB- — — —Below investment grade and not rated — 2 (2)

Total $ 159 $ 4 $ 155

(1) SCE assigns a credit rating based on the lower of a counterparty’s S&P or Moody’s rating. Forease of reference, the above table uses the S&P classifications to summarize risk, but reflects thelower of the two credit ratings.

(2) Exposure excludes amounts related to contracts classified as normal purchase and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheet,except for any related net accounts receivable.

The credit risk exposure set forth in the above table is comprised of $10 million of net accounts receivableand payables and $145 million representing the fair value, adjusted for counterparty credit reserves, ofderivative contracts.

Due to recent developments in the financial markets, the credit ratings may not be reflective of the relatedcredit risk. The CAISO comprises 35% of the total net exposure above and is mainly related to purchases ofCRRs and FTRs (see “— Commodity Price Risk” for further information). Certain of SCE’s long-term tollingagreements comprise 36% of the total net exposure.

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EDISON MISSION GROUP

EMG: LIQUIDITY

Liquidity

At December 31, 2008, EMG and its subsidiaries had cash and cash equivalents and short-term investments of$1.97 billion. EMG’s subsidiaries had a total of $81 million of available borrowing capacity under their creditfacilities. EME had a total of $59 million of available borrowing capacity under its $600 million corporatecredit facility, and Midwest Generation had a total of $22 million of available borrowing capacity under its$500 million working capital facility. EMG’s consolidated debt at December 31, 2008 was $4.8 billion. Inaddition, EME’s subsidiaries had $3.6 billion of long-term lease obligations related to their sale-leasebacktransactions that are due over periods ranging up to 26 years.

The following table summarizes the status of the EME and Midwest Generation credit facilities atDecember 31, 2008:

In millions EMEMidwest

Generation

Commitment $ 600 $ 500Less: Commitment from Lehman Brothers subsidiary (36) —

564 500Outstanding borrowings (376) (475)Outstanding letters of credit (129) (3)

Amount available $ 59 $ 22

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of theU.S. Bankruptcy Code. A subsidiary of Lehman Brothers Holdings, Lehman Commercial Paper Inc., a lenderin EME’s credit agreement representing a commitment of $36 million, in September 2008 declined requestsfor funding under that agreement and in October 2008, filed for bankruptcy protection. Another subsidiary ofLehman Brothers Holdings, Lehman Brothers Commercial Bank, Inc., is one of the lenders in the MidwestGeneration working capital facility. This subsidiary fully funded $42 million of Midwest Generation’sborrowing requests, which remains outstanding. At December 31, 2008, Lehman Brothers Commercial Bank’sshare of the amount available to draw under the Midwest Generation working capital facility was $2 million.

Disruptions in the capital markets affected in 2008, and may continue to affect, EME’s ability to financealready-developed wind projects and future commitments and projects, including significant outstandingcapital commitments for wind turbines. Access to the capital markets has become subject to increaseduncertainty due to the financial market and economic conditions discussed in “Edison International:Management Overview.” Accordingly, EME’s liquidity is currently comprised of cash on hand and cash flowgenerated from operations. Pending recovery of the capital markets, EME intends to preserve capital byfocusing on a selective growth strategy (primarily completion of projects under construction, including the BigSky wind project in Illinois, and development of projects deploying current turbine commitments), and usingits cash and future cash flow to meet its existing contractual commitments. Moreover, disruption in thefinancial markets appears to have reduced trading activity in power markets which may affect the level andduration of future hedging activity and potentially increase the volatility of earnings. Long-term disruption inthe capital markets could adversely affect EME’s business plans and financial position.

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Business Development

EME has undertaken a number of activities in 2008 with respect to wind projects, including the following:

• Completed the acquisition of a 240 MW planned wind project in Illinois, referred to as the Big Sky windproject with payments tied to various milestones. For further discussion refer to “— CapitalExpenditures — Expenditures for New Projects — Big Sky Wind Project.”

• Acquired and/or completed development and commenced construction with completion scheduled for 2009of the 80 MW Elkhorn Ridge project located in Nebraska and the 100 MW High Lonesome wind projectlocated in New Mexico. The estimated capital cost of these projects, excluding capitalized interest, isexpected to be approximately $306 million. EME owns 66.67% of the Elkhorn Ridge wind project and100% of the High Lonesome wind project. Each project will, after its completion, sell electricity pursuantto power sales agreements.

• Completed development and/or construction and commenced operations of the 38 MW Lookout windproject and the 29 MW Forward wind project, both located in Pennsylvania, the 50 MW Jeffers windproject and the 20 MW Odin wind project, both located in Minnesota, Phase I (80 MW) of the Goat Windproject in Texas, the 19 MW Spanish Fork wind project located in Utah, the 19 MW Buffalo Bear windproject located in Oklahoma, the 61 MW Mountain Wind I and the 80 MW Mountain Wind II projects,both located in Wyoming.

In addition, EME submitted bids in competitive solicitations to supply power from solar projects underdevelopment in the southwestern United States. Initial site and equipment selection have been completed alongwith preliminary economic feasibility studies. Further project development activities are underway to obtaintransmission interconnection, site control, and construction costs estimates, and to negotiate power salesagreements. To support development activities, EME entered into an agreement with First Solar Electric, LLCto provide design, engineering, procurement, and construction services for solar projects for identifiedcustomers, subject to the satisfaction of certain contingencies and entering into definitive agreements for suchservices for each project.

Capital Expenditures

At December 31, 2008, the estimated capital expenditures through 2011 by EME’s subsidiaries for existingprojects, corporate activities and turbine commitments were as follows:

In millions 2009 2010 2011

Illinois PlantsPlant capital expenditures $ 65 $ 106 $ 76Environmental expenditures 48 (a) (a)

Homer City FacilitiesPlant capital expenditures 29 55 29Environmental expenditures 8 14 32

New ProjectsProjects under construction 73 — —Turbine commitments 706 232 —

Other capital expenditures 35 9 7

Total $ 964 $ 416 $ 144

(a) See discussion below regarding capital expenditures for environmentalimprovements at the Illinois Plants.

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Expenditures for Existing Projects

Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls,replacement of major boiler components, mill steam inerting projects, generator stator rewinds, 4Kvswitchgear and main power transformer replacement.

As discussed above, Midwest Generation is subject to various commitments with respect to environmentalcompliance. Midwest Generation is in the process of completing engineering work for the potential installationof SCR and FGD equipment on Units 5 and 6 at the Powerton Station and SNCR equipment on Unit 6 at theJoliet Station. If a decision was made to proceed with these improvements the estimated capital costs (in 2008dollars) would be approximately:

• $1 billion for FGD equipment at the Powerton Station,

• $500 million for SCR equipment at the Powerton Station, and

• $13 million for SNCR equipment on Unit 6 at the Joliet Station.

Midwest Generation has determined that these capital expenditures could be reduced if the construction worksequence of FGD and SCR at the Powerton Station were reversed. The complexity of the Powerton Stationinstallation and construction interferences are representative of the balance of the fleet and MidwestGeneration currently estimates approximately $650/kW for any FGD installation it elects to make on otherunits.

A decision to make these improvements has not been made. Midwest Generation is still reviewing alltechnology and unit shutdown combinations, including interim and alternative compliance solutions. Forfurther discussion of environmental regulations and current status of environmental improvements in Illinois,see “Other Developments — Environmental Matters.”

Expenditures for New Projects

At December 31, 2008, EME had committed to purchase turbines (as reflected in the above table of capitalexpenditures) for wind projects that aggregate 942 MW. The turbine commitments generally representapproximately two-thirds of the total capital costs of EME’s wind projects. As of December 31, 2008, EMEhad a development pipeline of potential wind projects with projected installed capacity of approximately5,000 MW. The development pipeline represents potential projects with respect to which EME either owns theproject rights or has exclusive acquisition rights. Completion of development of a wind project may take anumber of years due to factors that include local permit requirements, willingness of local utilities to purchaserenewable power at sufficient prices to earn an appropriate rate of return, and availability and prices ofequipment. Furthermore, successful completion of a wind project is dependent upon obtaining permits andagreements necessary to support an investment. There is no assurance that each project included in thedevelopment pipeline currently or added in the future will be successfully completed, or that EME will be ableto successfully develop projects utilizing all of its turbine commitments. EME may also postpone or cancelwind turbine commitments, subject to the provisions of the relevant contracts.

Big Sky Wind Project

The Big Sky wind project is a 240 MW planned wind project in Illinois. EME has commenced pre-construction activities for equipment purchases, site development and interconnection activities ($99 millioncapitalized at December 31, 2008). Release of the project for full construction is pending a decision onselection of turbines. The costs to complete the Big Sky wind project, including construction and turbinetransportation and installation, are approximately $165 million. This estimate excludes the turbine costs setforth as turbine commitments in the table above and costs incurred to date. Upon completion, the project plansto sell electricity into the PJM market as a merchant generator or to local utilities under power sales contracts.

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Walnut Creek Project

Walnut Creek Energy, a subsidiary of EME, was awarded by SCE, through a competitive bidding process, aten-year power sales contract starting in 2013 for the output of the Walnut Creek project. In December 2008,EME and Walnut Creek Energy cancelled the turbine order for the Walnut Creek project pending resolution ofthe legal challenges discussed below and recorded a pre-tax charge of $23 million ($14 million, after tax).EME plans to purchase turbines for the project subject to resolution of uncertainty regarding the availability ofrequired emission credits.

In the air basins regulated by SCAQMD, the need for particulate matter (PM10) and SO2emission creditsexceeds available supply, and it is difficult to create new credits. Walnut Creek will be unable to beginconstruction until the legal challenges to the Priority Reserve emission credits have been favorably resolved oranother source of credits for the project has been identified. The capital costs to construct this project,excluding interest, are estimated in the range of $500 million to $600 million. See “Other Developments —Environmental Matters — Priority Reserve Legal Challenges” for more information.

Credit Ratings

Overview

Credit ratings for EMG’s direct and indirect subsidiaries at December 31, 2008, were as follows:

Moody’s Rating S&P Rating Fitch Rating

EME B1 BB- BB-Midwest Generation(1) Baa3 BB+ BBB-EMMT Not Rated BB- Not RatedEdison Capital (Edison Funding) Ba1 BB+ Not Rated

(1) First priority senior secured rating.

On December 23, 2008, S&P assigned a negative outlook to its corporate ratings for EME, MidwestGeneration, and EMMT. S&P assigned a negative outlook to Edison Funding’s credit rating and in August2008, Moody’s placed Edison Funding’s senior notes under review for a possible rating downgrade. EMGcannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain ineffect for any given period of time or that one or more of these ratings will not be lowered. EMG notes thatthese credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any timeby a rating agency.

EMG does not have any “rating triggers” contained in subsidiary financings that would result in it being requiredto make equity contributions or provide additional financial support to its subsidiaries, including EMMT.

Credit Rating of EMMT

The Homer City sale-leaseback documents restrict EME Homer City’s ability to enter into trading activities, asdefined in the documents, with EMMT to sell forward the output of the Homer City facilities if EMMT doesnot have an investment grade credit rating from S&P or Moody’s or, in the absence of those ratings, if it is notrated as investment grade pursuant to EME’s internal credit scoring procedures. These documents include arequirement that the counterparty to such transactions, and EME Homer City, if acting as seller to anunaffiliated third party, be investment grade. During 2008, EME sold all the output from the Homer Cityfacilities through EMMT, which has a below investment grade credit rating, and EME Homer City is notrated. In order to continue to sell forward the output of the Homer City facilities through EMMT, either: (1) aconsent from the sale-leaseback owner participant must be obtained; or (2) EMMT must provide assurances ofperformance consistent with the requirements of the sale-leaseback documents. EME has obtained a consentfrom the sale-leaseback owner participants that allows EME Homer City to enter into such sales, underspecified conditions, through March 1, 2014. EME is permitted to sell the output of the Homer City facilities

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into the spot market at any time. See “EMG: Market Risk Exposures — Commodity Price Risk — EnergyPrice Risk Affecting Sales from the Homer City Facilities.”

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

In connection with entering into contracts, EMMT may be required to support its risk of nonperformancethrough parent guarantees, margining or other credit support. EME has entered into guarantees in support ofEMMT’s hedging and trading activities; however, because the credit ratings of EMMT and EME are belowinvestment grade, EME has historically also provided collateral in the form of cash and letters of credit for thebenefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses, andunrealized gains in connection with these hedging and trading activities. At December 31, 2008, EMMT haddeposited $43 million in cash with clearing brokers in support of futures contracts and had deposited$45 million in cash with counterparties in support of forward energy and congestion contracts. In addition,EME had received cash collateral of $225 million at December 31, 2008, to support credit risk ofcounterparties under margin agreements.

Future cash collateral requirements may be higher than the margin and collateral requirements atDecember 31, 2008, if wholesale energy prices or the amount hedged changes. EME estimates that margin andcollateral requirements for energy and congestion contracts outstanding as of December 31, 2008 couldincrease by approximately $140 million over the remaining life of the contracts using a 95% confidence level.Certain EMMT hedge contracts do not require margining, but contain provisions that require EME or MidwestGeneration to comply with the terms and conditions of their credit facilities. The credit facilities containfinancial covenants which are described further in “— Dividend Restrictions in Major Financings.”Furthermore, the hedge contracts include provisions relating to a change in control or material adverse effectresulting from amendments or modifications to the related credit facility. Failure by EME or MidwestGeneration to comply with these provisions would result in a termination event under the hedge contracts,enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediatepayment of amounts owed to them. EMMT also has hedge contracts that do not require margining, but containthe right of each party to request additional credit support in the form of adequate assurance of performance inthe case of an adverse development affecting the other party. The aggregate fair value of hedge contracts withcredit-risk related contingent features was a net asset at December 31, 2008 and, accordingly, the contingentfeatures described above do not currently have a liquidity exposure. Future increases in power prices couldexpose EME or Midwest Generation to termination payments or posting additional collateral under thecontingent features described above.

Midwest Generation has cash on hand to support margin requirements specifically related to contracts enteredinto by EMMT related to the Illinois Plants. At December 31, 2008, Midwest Generation had available$22 million of borrowing capacity under its $500 million working capital facility. In addition, EME has cashon hand and $59 million of borrowing capacity available under its $600 million working capital facility toprovide credit support to subsidiaries.

Intercompany Tax-Allocation Agreement

EME and Edison Capital are included in the consolidated federal and combined state income tax returns ofEdison International and are eligible to participate in tax-allocation payments with other subsidiaries of EdisonInternational in circumstances where domestic tax losses are incurred. The rights of EME and Edison Capitalto receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of EMEand Edison Capital in the consolidated income tax returns of Edison International and its subsidiaries andother factors, including the consolidated taxable income of Edison International and its subsidiaries, theamount of net operating losses and other tax items of EMG’s subsidiaries, and other subsidiaries of EdisonInternational and specific procedures regarding allocation of state taxes. EME and Edison Capital receive tax-allocation payments for tax losses when and to the extent that the consolidated Edison International groupgenerates sufficient taxable income in order to be able to utilize EME’s or Edison Capital’s consolidated tax

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losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on theapplication of the factors cited above, each of EME and Edison Capital is obligated during periods it generatestaxable income, to make payments under the tax-allocation agreements. EME made net tax-allocationpayments to Edison International of $95 million, $112 million and $151 million in 2008, 2007 and 2006,respectively. Edison Capital made net tax-allocation payments to Edison International of $15 million in 2008and received net tax-allocation payments from Edison International of $17 million and $135 million in 2007and 2006, respectively. MEHC (parent) made net tax-allocation payments to Edison International of $3 millionin 2008 and received net tax-allocation payments from Edison International of $48 million and $43 million in2007 and 2006, respectively.

Dividend Restrictions in Major Financings

General

Each of EMG’s direct or indirect subsidiaries is organized as a legal entity separate and apart from EMG andits other subsidiaries. Assets of EMG’s subsidiaries are not available to satisfy the obligations of any of itsother subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject toapplicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividendsor otherwise distributed or contributed to EMG or to its subsidiary holding companies.

Key Ratios of EMG’s Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EME’s principal subsidiaries required by financing arrangements atDecember 31, 2008 or for the 12 months ended December 31, 2008:

Subsidiary Financial Ratio Covenant Actual

Midwest Generation (Illinois Plants) Debt to CapitalizationRatio

Less than or equal to0.60 to 1

0.28 to 1

EME Homer City (Homer City facilities) Senior Rent ServiceCoverage Ratio

Greater than 1.7 to 1 2.05 to 1

Edison Capital’s ability to make dividend payments is currently restricted by covenants in its financialinstruments, which require Edison Capital, through a wholly owned subsidiary, to maintain a specifiedminimum net worth of $200 million. Edison Capital satisfied this minimum net worth requirement as ofDecember 31, 2008.

Midwest Generation Financing Restrictions on Distributions

Midwest Generation is bound by the covenants in its credit agreement and certain covenants under thePowerton-Joliet lease documents with respect to Midwest Generation making payments under the leases.These covenants include restrictions on the ability to, among other things, incur debt, create liens on itsproperty, merge or consolidate, sell assets, make investments, engage in transactions with affiliates, makedistributions, make capital expenditures, enter into agreements restricting its ability to make distributions,engage in other lines of business, enter into swap agreements, or engage in transactions for any speculativepurpose. In order for Midwest Generation to make a distribution, it must be in compliance with the covenantsspecified under its credit agreement, including maintaining a debt to capitalization ratio of no greater than0.60 to 1.

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EME Homer City (Homer City Facilities)

EME Homer City completed a sale-leaseback of the Homer City facilities in December 2001. In order tomake a distribution, EME Homer City must be in compliance with the covenants specified in the leaseagreements, including the following financial performance requirements measured on the date of distribution:

• At the end of each quarter, the senior rent service coverage ratio for the prior twelve-month period (takenas a whole) must be greater than 1.7 to 1. The senior rent service coverage ratio is defined as all incomeand receipts of EME Homer City less amounts paid for operating expenses, required capital expenditures,taxes and financing fees divided by the aggregate amount of the debt portion of the rent, plus fees,expenses and indemnities due and payable with respect to the lessor’s debt service reserve letter of credit.

• At the end of each quarter, the equity and debt portions of rent then due and payable must have been paid.The senior rent service coverage ratio (discussed above) projected for each of the prospective two twelve-month periods must be greater than 1.7 to 1. No more than two rent default events may have occurred,whether or not cured. A rent default event is defined as the failure to pay the equity portion of the rentwithin five business days of when it is due.

EME Corporate Credit Facility Restrictions on Distributions from Subsidiaries

EME’s corporate credit facility contains covenants that restrict its ability, and the ability of several of itssubsidiaries, to make distributions. This restriction binds the subsidiaries through which EME owns theWestside projects, the Sunrise project, the Illinois Plants, the Homer City facilities and the Big 4 projects.These subsidiaries would not be able to make a distribution to EME if an event of default were to occur andbe continuing under EME’s corporate credit facility after giving effect to the distribution. In addition, EMEgranted a security interest in an account into which all distributions received by it from the Big 4 projects aredeposited. EME is free to use these distributions unless and until an event of default occurs under its corporatecredit facility.

EME’s Credit Facility Financial Ratios

EME’s credit facility contains financial covenants which require EME to maintain a minimum interestcoverage ratio and a maximum corporate debt-to-corporate capital ratio as such terms are defined in the creditfacility. The key ratios at December 31, 2008 or for the 12 months ended December 31, 2008 are as follows:

Financial Ratio Covenant Actual

Interest Coverage Ratio Not less than 1.2 to 1 1.98 to 1Corporate Debt to Corporate Capital Ratio Not more than 0.75 to 1 0.60 to 1

EME’s Senior Notes and Guaranty of Powerton-Joliet Leases

EME is restricted from the sale or disposition of assets, which includes the making of a distribution, if theaggregate net book value of all such sales during the most recent 12-month period would exceed 10% ofconsolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscalquarter preceding such sale. At December 31, 2008, the maximum sale or disposition of EME assets isapproximately $800 million. This limitation does not apply if the proceeds are invested in assets in similar orrelated lines of business of EME. Furthermore, EME may sell or otherwise dispose of assets in excess of such10% limitation if the proceeds from such sales or dispositions, which are not reinvested as provided above, areretained by EME as cash or cash equivalents or are used by EME to repay senior debt of EME or debt of itssubsidiaries.

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EMG: OTHER DEVELOPMENTS

RPM Buyers’ Complaint

On May 30, 2008, a group of entities referring to themselves as the “RPM Buyers” filed a complaint at theFERC asking that PJM’s RPM, as implemented through the transitional base residual auctions establishingcapacity payments for the period from June 1, 2008 through May 31, 2011, be found to have produced unjustand unreasonable capacity prices. On September 19, 2008, the FERC dismissed the RPM Buyers’ complaint,finding that the RPM Buyers had failed to allege or prove that any party violated PJM’s tariff and marketrules, and that the prices determined during the transition period were determined in accordance with PJM’sFERC-approved tariff. On October 20, 2008, the RPM Buyers requested rehearing of the FERC’s orderdismissing their complaint. This matter is currently pending before the FERC. EME cannot predict theoutcome of this matter.

Midwest Generation New Source Review Notice of Violation

On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in theearly 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacementprojects at six Illinois coal-fired electric generating stations in violation of the Prevention of SignificantDeterioration requirements and of the New Source Performance Standards of the CAA, including allegedrequirements to obtain a construction permit and to install best available control technology at the time of theprojects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certainoperating permit requirements under Title V of the CAA. Finally, the US EPA alleges violations of certainopacity and particulate matter standards at the Illinois Plants. The NOV does not specify the penalties or otherrelief that the US EPA seeks for the alleged violations. Midwest Generation, Commonwealth Edison, the USEPA, and the DOJ are in talks designed to explore the possibility of a settlement. If the settlement talks failand the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. MidwestGeneration cannot predict the outcome of this matter or estimate the impact on its facilities, its results ofoperations, financial position or cash flows.

On August 13, 2007, Midwest Generation and Commonwealth Edison received a letter signed by severalChicago-based environmental action groups stating that, in light of the NOV, the groups are examining thepossibility of filing a citizen suit against Midwest Generation and Commonwealth Edison based presumablyon the same or similar theories advanced by the US EPA in the NOV.

By letter dated August 8, 2007, Commonwealth Edison advised EME that Commonwealth Edison believes itis entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a resultof the NOV. By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification toEME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if theenvironmental groups were to file suit. Midwest Generation and Commonwealth Edison are cooperating withone another in responding to the NOV.

EME Homer City New Source Review Notice of Violation

On June 12, 2008, EME Homer City received an NOV from the US EPA alleging that, beginning in 1988,EME Homer City (or former owners of the Homer City facilities) performed repair or replacement projects atHomer City Units 1 and 2 without first obtaining construction permits as required by the Prevention ofSignificant Deterioration requirements of the CAA. The US EPA also alleges that EME Homer City has failedto file timely and complete Title V permits. The NOV does not specify the penalties or other relief that theUS EPA seeks for alleged violations. EME Homer City has met with the US EPA and has expressed its intentto explore the possibility of a settlement. If no settlement is reached and the DOJ files suit, litigation couldtake many years to resolve the issues alleged in the NOV. EME Homer City cannot predict at this time whateffect this matter may have on its facilities, its results of operations, financial position or cash flows.

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EME Homer City has sought indemnification for liability and defense costs associated with the NOV from thesellers under the asset purchase agreement pursuant to which EME Homer City acquired the Homer Cityfacilities. The sellers responded by denying the indemnity obligation, but accepting the defense of the claims.

EME Homer City notified the sale-leaseback owner participants of the Homer City facilities of the NOV underthe operative indemnity provisions of the sale-leaseback documents. The owner participants of the Homer Cityfacilities, in turn, have sought indemnification and defense from EME Homer City for costs and liabilityassociated with the EME Homer City NOV. EME Homer City responded by undertaking the indemnityobligation and defense of the claims.


Edison International files its federal and state income tax returns on a consolidated basis and files on acombined basis in California and certain other states. EMG is included in the consolidated federal and statecombined income tax returns. See “Other Developments — Federal and State Income Taxes” for furtherdiscussion of these matters.

EMG: MARKET RISK EXPOSURES

Introduction

EMG’s primary market risk exposures are associated with the sale of electricity and capacity from, and theprocurement of fuel for, its merchant power plants. These market risks arise from fluctuations in electricity,capacity and fuel prices, emission allowances, and transmission rights. Additionally, EME’s financial resultscan be affected by fluctuations in interest rates. EME manages these risks in part by using derivative financialinstruments in accordance with established policies and procedures.

Commodity Price Risk

Introduction

EME’s merchant operations expose it to commodity price risk, which represents the potential loss that can becaused by a change in the market value of a particular commodity. Commodity price risks are activelymonitored by a risk management committee to ensure compliance with EME’s risk management policies.Policies are in place which define risk management processes, and procedures exist which allow formonitoring of all commitments and positions with regular reviews by EME’s risk management committee.Despite this, there can be no assurance that all risks have been accurately identified, measured and/ormitigated.

In addition to prevailing market prices, EME’s ability to derive profits from the sale of electricity will beaffected by the cost of production, including costs incurred to comply with environmental regulations. Thecosts of production of the units vary and, accordingly, depending on market conditions, the amount ofgeneration that will be sold from the units is expected to vary.

EME uses “gross margin at risk” to identify, measure, monitor and control its overall market risk exposurewith respect to hedge positions at the Illinois Plants, the Homer City facilities, and the merchant windprojects, and “value at risk” to identify, measure, monitor and control its overall risk exposure in respect of itstrading positions. The use of these measures allows management to aggregate overall commodity risk,compare risk on a consistent basis and identify the risk factors. Value at risk measures the possible loss, andgross margin at risk measures the potential change in value, of an asset or position, in each case over a giventime interval, under normal market conditions, at a given confidence level. Given the inherent limitations ofthese measures and reliance on a single type of risk measurement tool, EME supplements these approacheswith the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss triggersand counterparty credit exposure limits.

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Hedging Strategy

To reduce its exposure to market risk, EME hedges a portion of its electricity sales through EMMT, an EMEsubsidiary engaged in the power marketing and trading business. To the extent that EME does not hedge itselectricity sales, the unhedged portion will be subject to the risks and benefits of spot market pricemovements. Hedge transactions are primarily implemented through:

• the use of futures contracts cleared on the Intercontinental Trading Exchange and the New York MercantileExchange or executed bilaterally with counterparties,

• forward sales transactions entered into on a bilateral basis with third parties, including electric utilities andpower marketing companies,

• full requirements services contracts or load requirements services contracts for the procurement of powerfor electric utilities’ customers, with such services including the delivery of a bundled product including,but not limited to, energy, transmission, capacity, and ancillary services, generally for a fixed unit price,and

• participation in capacity auctions.

The extent to which EME hedges its market price risk depends on several factors. First, EME evaluatesover-the-counter market prices to determine whether the types of hedge transactions set forth above at forwardmarket prices are sufficiently attractive compared to assuming the risk associated with fluctuating spot marketsales. Second, EME’s ability to enter into hedging transactions depends upon its and Midwest Generation’scredit capacity and upon the forward sales markets having sufficient liquidity to enable EME to identifyappropriate counterparties for hedging transactions.

In the case of hedging transactions related to the generation and capacity of the Illinois Plants, MidwestGeneration is permitted to use its working capital facility and cash on hand to provide credit support for thesehedging transactions entered into by EMMT under an energy services agreement between Midwest Generationand EMMT. Utilization of this credit facility in support of hedging transactions provides additional liquiditysupport for implementation of EME’s contracting strategy for the Illinois Plants. In addition, MidwestGeneration may grant liens on its property in support of hedging transactions associated with the IllinoisPlants. See “— Credit Risk” below.

In the case of hedging transactions related to the generation and capacity of the Homer City facilities, creditsupport is provided by EME.

Energy Price Risk Affecting Sales from the Illinois Plants

All the energy and capacity from the Illinois Plants is sold under terms, including price and quantity, arrangedby EMMT with customers through a combination of bilateral agreements (resulting from negotiations or fromauctions), forward energy sales and spot market sales. As discussed further below, power generated at theIllinois Plants is generally sold into the PJM market.

Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing. Hedgingtransactions related to the generation of the Illinois Plants are generally entered into at the Northern IllinoisHub or the AEP/Dayton Hub, both in PJM, or may be entered into at other trading hubs, including theCinergy Hub in the MISO. These trading hubs have been the most liquid locations for hedging purposes. See“— Basis Risk” below for further discussion.

PJM has a short-term market, which establishes an hourly clearing price. The Illinois Plants are situated in thePJM control area and are physically connected to high-voltage transmission lines serving this market.

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The following table depicts the average historical market prices for energy per megawatt-hour during 2008,2007 and 2006:

2008 2007 2006

24-Hour Northern Illinois HubHistorical Energy Prices(1)

January $ 47.09 $ 35.75 $ 42.27February 54.46 56.64 42.66March 58.58 42.04 42.50April 53.87 48.91 43.16May 44.49 44.49 39.96June 56.06 39.76 34.80July 63.79 43.40 51.82August 52.66 57.97 54.76September 43.08 39.68 31.87October 35.31 50.14 37.80November 38.34 43.25 41.90December 40.43 44.36 33.57

Yearly Average $ 49.01 $ 45.53 $ 41.42

(1) Energy prices were calculated at the Northern Illinois Hub delivery point usinghourly real-time prices as published by PJM.

Forward market prices at the Northern Illinois Hub fluctuate as a result of a number of factors, includingnatural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn isaffected by weather, economic growth, and other factors), plant outages in the region, and the amount ofexisting and planned power plant capacity. The actual spot prices for electricity delivered by the Illinois Plantsinto these markets may vary materially from the forward market prices set forth in the table below.

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The following table sets forth the forward month-end market prices for energy per megawatt-hour for thecalendar year 2009 and calendar year 2010 “strips,” which are defined as energy purchases for the entirecalendar year, as quoted for sales into the Northern Illinois Hub during 2008:

2009 2010

24-Hour Northern Illinois HubForward Energy Prices(1)

January 31, 2008 $ 52.30 $ 53.14February 29, 2008 57.29 56.45March 31, 2008 55.48 55.50April 30, 2008 56.80 49.14May 31, 2008 57.03 52.10June 30, 2008 62.17 56.08July 31, 2008 52.48 50.94August 31, 2008 50.49 49.30September 30, 2008 48.03 48.52October 31, 2008 42.03 43.10November 30, 2008 41.43 42.45December 31, 2008 38.59 39.55

(1) Energy prices were determined by obtaining broker quotes and information fromother public sources relating to the Northern Illinois Hub delivery point.

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EMMT engages in hedging activities for the Illinois Plants to hedge the risk of future change in the price ofelectricity. Hedging activities for energy only contracts are typically weighted toward on-peak periods. Thefollowing table summarizes Midwest Generation’s hedge position at December 31, 2008:

GWh

Averageprice/MWh GWh

Averageprice/MWh GWh

Averageprice/MWh

2009 2010 2011

Energy Only Contracts(1)

Northern Illinois Hub — AEP/Dayton Hub 9,945 $ 65.44 6,555 $ 68.61 612 $ 76.40Load Requirements Services Contracts(2)(3)

Northern Illinois Hub 1,571 $ 63.65 — — — —

Total estimated GWh 11,516 6,555 612

(1) The energy only contracts include forward contracts for the sale of power and futures contracts duringdifferent periods of the year and the day. Market prices tend to be higher during on-peak periods andduring summer months, although there is significant variability of power prices during different periods oftime. Accordingly, the above hedge positions at December 31, 2008 are not directly comparable to the24-hour Northern Illinois Hub prices set forth above.

(2) Under a load requirements services contract, the amount of power sold is a portion of the retail load of thepurchasing utility and thus can vary significantly with variations in that retail load. Retail load dependsupon a number of factors, including the time of day, the time of the year and the utility’s number of newand continuing customers. Estimated GWh have been forecast based on historical patterns and onassumptions regarding the factors that may affect retail loads in the future. The actual load will vary fromthat used for the above estimate, and the amount of variation may be material.

(3) The average price per MWh under a load requirements services contract (which is subject to a seasonalprice adjustment) represents the sale of a bundled product that includes, but is not limited to, energy,capacity and ancillary services. Furthermore, as a supplier of a portion of a utility’s load, MidwestGeneration will incur charges from PJM as a load-serving entity. For these reasons, the average price perMWh under a load requirements services contract is not comparable to the sale of power under an energyonly contract. The average price per MWh under a load requirements services contract represents the saleof the bundled product based on an estimated customer load profile.

Energy Price Risk Affecting Sales from the Homer City Facilities

All the energy and capacity from the Homer City facilities is sold under terms, including price and quantity,arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiationsor from auctions), forward energy sales and spot market sales. Electric power generated at the Homer Cityfacilities is generally sold into the PJM market. PJM has a short-term market, which establishes an hourlyclearing price. The Homer City facilities are situated in the PJM control area and are physically connected tohigh-voltage transmission lines serving both the PJM and NYISO markets.

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The following table depicts the average historical market prices for energy per megawatt-hour at the HomerCity busbar and in PJM West Hub (EME Homer City’s primary trading hub) during the past three years:

2008 2007 2006 2008 2007 2006

Homer City Busbar PJM West Hub

Historical Energy Prices(1)

24-Hour PJM

January $ 54.32 $ 40.30 $ 48.67 $ 66.80 $ 44.63 $ 54.57February 61.74 64.27 49.54 68.29 73.93 56.39March 65.37 55.00 53.26 70.48 61.02 58.30April 61.99 52.42 48.50 69.12 58.74 49.92May 49.37 48.12 44.71 59.84 53.89 48.55June 78.72 45.88 38.78 98.50 60.19 45.78July 72.39 48.23 53.68 91.80 58.89 63.47August 60.16 55.44 58.60 73.91 71.00 76.57September 52.33 48.90 33.26 66.04 60.14 34.40October 44.46 53.89 37.42 52.88 61.11 39.65November 44.99 47.27 40.13 54.50 55.25 44.83December 46.74 52.58 35.29 50.62 59.67 40.53

Yearly Average $ 57.72 $ 51.03 $ 45.15 $ 68.56 $ 59.87 $ 51.08

(1) Energy prices were calculated at the Homer City busbar (delivery point) and PJM West Hub usinghistorical hourly real-time prices provided on the PJM web-site.

Forward market prices at the PJM West Hub fluctuate as a result of a number of factors, including natural gasprices, transmission congestion, changes in market rules, electricity demand (which in turn is affected byweather, economic growth and other factors), plant outages in the region, and the amount of existing andplanned power plant capacity. The actual spot prices for electricity delivered by the Homer City facilities intothese markets may vary materially from the forward market prices set forth in the table below.

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The following table sets forth the forward month-end market prices for energy per megawatt-hour for thecalendar year 2009 and calendar year 2010 “strips,” which are defined as energy purchases for the entirecalendar year, as quoted for sales into the PJM West Hub during 2008:

2009 2010

24-Hour PJM West HubForward Energy Prices(1)

January 31, 2008 $ 69.06 $ 68.43February 29, 2008 75.03 72.59March 31, 2008 75.55 71.76April 30, 2008 79.64 74.91May 31, 2008 83.91 78.42June 30, 2008 94.90 87.10July 31, 2008 75.89 73.66August 31, 2008 70.49 70.44September 30, 2008 66.23 68.31October 31, 2008 59.32 62.97November 30, 2008 58.17 62.39December 31, 2008 54.66 59.21

(1) Energy prices were determined by obtaining broker quotes and information fromother public sources relating to the PJM West Hub delivery point. Forward pricesat PJM West Hub are generally higher than the prices at the Homer City busbar.

EMMT engages in hedging activities for the Homer City facilities to hedge the risk of future change in theprice of electricity. Hedging activities are typically weighted toward on-peak periods. The following tablesummarizes EME Homer City’s hedge position at December 31, 2008:

2009 2010

GWh 4,096 2,662Average price/MWh(1) $ 82.94 $ 90.53

(1) The above hedge positions include forward contracts for the sale of power duringdifferent periods of the year and the day. Market prices tend to be higher duringon-peak periods and during summer months, although there is significantvariability of power prices during different periods of time. Accordingly, the abovehedge position at December 31, 2008 is not directly comparable to the 24-hourPJM West Hub prices set forth above.

The average price/MWh for EME Homer City’s hedge position is based on the PJM West Hub. Energy pricesat the Homer City busbar have been lower than energy prices at the PJM West Hub. See “— Basis Risk”below for a discussion of the difference.

Capacity Price Risk

On June 1, 2007, PJM implemented the RPM for capacity. The purpose of the RPM is to provide a long-termpricing signal for capacity resources. The RPM provides a mechanism for PJM to satisfy the region’s need forgeneration capacity, the cost of which is allocated to load-serving entities through a locational reliabilitycharge.

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The following table summarizes the status of capacity sales for Midwest Generation and EME Homer City atDecember 31, 2008:

MWPrice perMW-day MW

Price perMW-day MW

Price perMW-day

Through RPMAuction, Net

Non-unit SpecificCapacity Sales

VariableCapacity Sales

Fixed Price Capacity Sales

January 1, 2009 to May 31, 2009Midwest Generation 2,957 $ 122.41(1) 880 $ 64.35 — —EME Homer City 820 111.92 — — 905 $ 56.56(2)

June 1, 2009 to May 31, 2010Midwest Generation 4,582 102.04 723 72.84 — —EME Homer City 1,670 191.32 — — — —

June 1, 2010 to May 31, 2011Midwest Generation 4,929 174.29 — — — —EME Homer City 1,813 174.29 — — — —

June 1, 2011 to May 31, 2012Midwest Generation 4,582 110.00 — — — —EME Homer City 1,771 110.00 — — — —

(1) The original price of $111.92 was affected by Midwest Generation’s participation in a supplemental RPMauction during the first quarter of 2008 which resulted in purchasing certain capacity amounts at a price of$10 per MW-day, thereby reducing the aggregate forward capacity sales for this period and increasing theeffective capacity price to $122.41.

(2) Actual contract price is a function of NYISO capacity auction clearing prices in January through April2009 and forward over-the-counter NYISO capacity prices on December 31, 2008 for May 2009.

Revenues from the sale of capacity from Midwest Generation and EME Homer City beyond the periods setforth above will depend upon the amount of capacity available and future market prices either in PJM ornearby markets if EME has an opportunity to capture a higher value associated with those markets. UnderPJM’s RPM system, the market price for capacity is generally determined by aggregate market-based supplyconditions and an administratively set aggregate demand curve. Among the factors influencing the supply ofcapacity in any particular market are plant forced outage rates, plant closings, plant delistings (due to plantsbeing removed as capacity resources and/or to export capacity to other markets), capacity imports from othermarkets, and the CONE.

Midwest Generation entered into hedge transactions in advance of the RPM auctions with counterparties thatare settled through PJM. In addition, the load service requirements contracts entered into by MidwestGeneration with Commonwealth Edison include energy, capacity and ancillary services (sometimes referred toas a “bundled product”). Under PJM’s business rules, Midwest Generation sells all of its available capacity(defined as unit capacity less forced outages) into the RPM and is subject to a locational reliability charge forthe load under these contracts. This means that the locational reliability charge generally offsets the relatedamounts sold in the RPM, which Midwest Generation presents on a net basis in the table above.

Prior to the RPM auctions for the relevant delivery periods, EME Homer City sold a portion of its capacity toan unrelated third party for the delivery period of June 1, 2008 through May 31, 2009. EME Homer City isnot receiving the RPM auction clearing price for this previously sold capacity. The price EME Homer City isreceiving for these capacity sales is a function of NYISO capacity clearing prices resulting from separateNYISO capacity auctions.

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Basis Risk

Sales made from the Illinois Plants and the Homer City facilities in the real-time or day-ahead market receivethe actual spot prices or day-ahead prices, as the case may be, at the busbars (delivery points) of the individualplants. In order to mitigate price risk from changes in spot prices at the individual plant busbars, EME mayenter into cash settled futures contracts as well as forward contracts with counterparties for energy to bedelivered in future periods. Currently, a liquid market for entering into these contracts at the individual plantbusbars does not exist. A liquid market does exist for a settlement point at the PJM West Hub in the case ofthe Homer City facilities and for settlement points at the Northern Illinois Hub and the AEP/Dayton Hub inthe case of the Illinois Plants. EME’s hedging activities use these settlement points (and, to a lesser extent,other similar trading hubs) to enter into hedging contracts. EME’s revenues with respect to such forwardcontracts include:

• sales of actual generation in the amounts covered by the forward contracts with reference to PJM spotprices at the busbar of the plant involved, plus,

• sales to third parties at the price under such hedging contracts at designated settlement points (generallythe PJM West Hub for the Homer City facilities and the Northern Illinois Hub or AEP/Dayton Hub for theIllinois Plants) less the cost of power at spot prices at the same designated settlement points.

Under PJM’s market design, locational marginal pricing, which establishes market prices at specific locationsthroughout PJM by considering factors including generator bids, load requirements, transmission congestionand losses, can cause the price of a specific delivery point to be higher or lower relative to other locationsdepending on how the point is affected by transmission constraints. Effective June 1, 2007, PJM implementedmarginal losses which adjust the algorithm that calculates locational marginal prices to include a componentfor marginal transmission losses in addition to the component included for congestion. To the extent that, onthe settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices at thesettlement point, the proceeds actually realized from the related hedge contract are effectively reduced by thedifference. This is referred to as “basis risk.” During 2008, transmission congestion in PJM has resulted inprices at the Homer City busbar being lower than those at the PJM West Hub by an average of 16%,compared to 15% during 2007 and 12% during 2006. The monthly average difference during 2008 rangedfrom 7% to 21%. During 2008, transmission congestion in PJM has resulted in prices at the individual busbarsof the Illinois Plants being lower than those at the Northern Illinois Hub by an average of 2%.

By entering into cash settled futures contracts and forward contracts using the PJM West Hub, the NorthernIllinois Hub, and the AEP/Dayton Hub (or other similar trading hubs) as settlement points, EME is exposed tobasis risk as described above. In order to mitigate basis risk, EME may purchase financial transmission rightsand basis swaps in PJM for EME Homer City. A financial transmission right is a financial instrument thatentitles the holder to receive the difference of actual spot prices for two delivery points in exchange for afixed amount. Accordingly, EME’s hedging activities include using financial transmission rights alone or incombination with forward contracts and basis swap contracts to manage basis risk.

Coal and Transportation Price Risk

The Illinois Plants and the Homer City facilities purchase coal primarily obtained from the Southern PRB ofWyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made

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under a variety of supply agreements extending through 2012. The following table summarizes the amount ofcoal under contract at December 31, 2008 for the next four years:

2009 2010 2011 2012

Amount of Coal Under Contractin Millions of Equivalent Tons(1)

Illinois Plants 17.7 11.7 — —Homer City facilities(2) 5.1 0.6 0.3 0.1

(1) The amount of coal under contract in tons is calculated based on contracted tons andapplying an 8,800 Btu equivalent for the Illinois Plants and 13,000 Btu equivalent for theHomer City facilities.

(2) At December 31, 2008, there are options to purchase additional coal of 0.7 million tons in2010, 0.6 million tons in 2011, 0.5 million tons in 2012, and 0.1 million tons in 2013.Options to purchase 1.2 million tons in 2010 and 2011 are the subject of a dispute with thesupplier. Pending dispute resolution, EME is exposed to price risk related to these volumesat December 31, 2008.

EME is subject to price risk for purchases of coal that are not under contract. Prices of NAPP coal, which arerelated to the price of coal purchased for the Homer City facilities, increased substantially during 2008 andincreased steadily during 2007 from 2006. The price of NAPP coal (with 13,000 Btu per pound heat contentand G3.0 pounds of SO2 per MMBtu sulfur content) ranged from $61.75 per ton to $150 per ton during 2008and decreased to a price of $76 per ton at January 9, 2009, as reported by the EIA. The 2008 increase inNAPP coal prices was primarily attributable to increased international and Atlantic basin coal demandresulting from a variety of factors in several countries consuming this coal. The current global economicconditions have tempered this demand and prices moderated as 2008 came to a close. In 2007, the price ofNAPP coal fluctuated between $44.00 per ton to $55.25 per ton, which was the price per ton at December 21,2007, as reported by the EIA. In 2006, the price of NAPP coal fluctuated between $37.50 per ton and $45.00per ton, with a price of $43.00 per ton at December 15, 2006, as reported by the EIA. The 2007 increase inthe NAPP coal price was in line with normal market price volatility.

Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content)purchased for the Illinois Plants increased during 2008 from 2007 year-end prices and increased during 2007from 2006 year-end prices. The 2008 and 2007 fluctuations in PRB coal prices were in line with normalmarket price volatility. The price of PRB coal fluctuated between $11 per ton to $14.50 per ton during 2008,with a price of $13 per ton at January 9, 2009, as reported by the EIA. In 2007, the price of PRB coal rangedfrom $8.35 per ton to $11.50 per ton, which was the price per ton at December 21, 2007. In 2006, the price ofPRB coal ranged from $20.66 per ton in January 2006 to $9.90 per ton at December 15, 2006, as reported bythe EIA.

EME has contractual agreements for the transport of coal to its facilities. The primary contract is with UnionPacific Railroad (and various delivering carriers), which extends through 2011. EME is exposed to price riskrelated to higher transportation rates after the expiration of its existing transportation contracts. Currenttransportation rates for PRB coal are higher than the existing rates under contract (transportation costs aremore than 50% of the delivered cost of PRB coal to the Illinois Plants).

Based on EME’s anticipated coal requirements in 2009 in excess of the amount under contract, EME expectsthat a 10% change in the price of coal at December 31, 2008 would increase or decrease pre-tax income in2009 by approximately $1 million.

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Emission Allowances Price Risk

The federal Acid Rain Program requires electric generating stations to hold SO2 allowances sufficient to covertheir annual emissions. Illinois and Pennsylvania regulations implemented the federal NOX SIP Call whichrequired, through 2008, the holding of NOX allowances to cover ozone season NOX emissions. In addition,pursuant to Pennsylvania’s and Illinois’ implementation of the CAIR, electric generation stations are requiredto hold seasonal and annual NOX allowances beginning January 1, 2009. As part of the acquisition of theIllinois Plants and the Homer City facilities, EME obtained the rights to the emission allowances that havebeen or are allocated to these plants. EME purchases (or sells) emission allowances based on the amountsrequired for actual generation in excess of (or less than) the amounts allocated under these programs. See“Other Developments — Environmental Matters — Air Quality Regulation — Clean Air Interstate Rule” forfurther discussion of the CAIR.

EME is subject to price risk for purchases of emission allowances required for actual emissions greater thanallowances held. The market price for emission allowances may vary significantly. For example, the averagepurchase price of SO2 allowances was $315 per ton in 2008, $512 per ton in 2007 and $664 per ton in 2006.Based on broker’s quotes and information from public sources, the spot price for SO2 allowances was $210per ton at December 31, 2008. EME does not anticipate any requirements to purchase SO2 emissionallowances for 2009.

Based on EME’s anticipated annual and seasonal NOX requirements for 2009 beyond those allowances alreadypurchased, EME expects that a 10% change in the price of annual and seasonal NOX emission allowances atDecember 31, 2008 would increase or decrease pre-tax income in 2009 by approximately $4 million.

See “Other Developments — Environmental Matters — Air Quality Regulation” for a discussion ofenvironmental regulations related to emissions.

Accounting for Energy Contracts

EME uses a number of energy contracts to manage exposure from changes in the price of electricity, includingforward sales and purchases of physical power and forward price swaps which settle only on a financial basis(including futures contracts). EME follows SFAS No. 133, and under this Standard these energy contracts aregenerally defined as derivative financial instruments. Importantly, SFAS No. 133 requires changes in the fairvalue of each derivative financial instrument to be recognized in earnings at the end of each accounting periodunless the instrument qualifies for hedge accounting under the terms of SFAS No. 133. For derivatives that doqualify for cash flow hedge accounting, changes in their fair value are recognized in other comprehensiveincome until the hedged item settles and is recognized in earnings. However, the ineffective portion of aderivative that qualifies for cash flow hedge accounting is recognized currently in earnings. For furtherdiscussion of derivative financial instruments, see “Management’s Overview; Critical Accounting Policies andEstimates — Critical Accounting Policies and Estimates — Derivative Financial Instruments and HedgingActivities.”

SFAS No. 133 affects the timing of income recognition, but has no effect on cash flow. To the extent thatincome varies under SFAS No. 133 from accrual accounting (i.e., revenue recognition based on settlement oftransactions), EME records unrealized gains or losses. Unrealized SFAS No. 133 gains or losses result from:

• energy contracts that do not qualify for hedge accounting under SFAS No. 133 (which are sometimesreferred to as economic hedges). Unrealized gains and losses include:

⁄ the change in fair value (sometimes called mark-to-market) of economic hedges that relate tosubsequent periods, and

⁄ offsetting amounts to the realized gains and losses in the period non-qualifying hedges are settled.

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• the ineffective portion of qualifying hedges which generally relate to changes in the expected basisbetween the sale point and the hedge point. Unrealized gains or losses include:

⁄ the current period ineffectiveness on the hedge program for subsequent periods. This occurs becausethe ineffective gains or losses are recorded in the current period, whereby the energy revenuesrelated to generation being hedged will be recorded in the subsequent period along with the effectiveportion of the related hedge transaction, and

⁄ offsetting amounts to the realized ineffective gains and losses in the period cash flow hedges aresettled.

EME classifies unrealized gains and losses from energy contracts as part of operating revenues. The results ofderivative activities are recorded as part of cash flows from operating activities in the consolidated statementsof cash flows. The following table summarizes unrealized gains (losses) from non-trading activities for thethree-year period ended December 31, 2008:

In millions Years Ended December 31, 2008 2007 2006

Illinois PlantsNon-qualifying hedges $ (16) $ (14) $ 28Ineffective portion of cash flow hedges 10 (11) 2

Homer City facilitiesNon-qualifying hedges 1 (1) 2Ineffective portion of cash flow hedges 20 (9) 33

Total unrealized gains (losses) $ 15 $ (35) $ 65

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of theU.S. Bankruptcy Code. EME had power contracts with Lehman Brothers Commodity Services, Inc., asubsidiary of Lehman Brothers Holdings, for Midwest Generation for 2009 and 2010. Lehman BrothersCommodity Services also filed for bankruptcy protection on October 3, 2008. The obligations of LehmanBrothers Commodity Services under the power contracts are guaranteed by Lehman Brothers Holdings. Thesecontracts qualified as cash flow hedges under SFAS No. 133 until EME dedesignated the power contractseffective September 12, 2008 when it determined that it was no longer probable that performance would occur.The amount recorded in accumulated comprehensive income (loss) related to the effective portion of thehedges was $24 million pre-tax on that date. Since the power contracts are no longer being accounted for ascash flow hedges under SFAS No. 133 and subsequently were terminated, the subsequent change in fair valuewas recorded as an unrealized loss in 2008. Under SFAS No. 133, the pre-tax amount recorded in accumulatedother comprehensive income (loss) will be reclassified to operating revenues based on the original forecastedtransactions in 2009 ($15 million) and 2010 ($9 million), unless it becomes probable that the forecastedtransactions will no longer occur.

At December 31, 2008, excluding the unrealized losses described above related to Lehman BrothersCommodity Services, unrealized gains of $1 million were recognized from non-qualifying hedge contracts orthe ineffective portion of cash flow hedges related to subsequent periods ($2 million in unrealized losses for2009 and $3 million in unrealized gains for 2010).

Fair Value of Financial Instruments

EME adopted SFAS No. 157 effective January 1, 2008. The standard established a hierarchy for fair valuemeasurements. See “Edison International Notes to Consolidated Financial Statements — Note 10. Fair ValueMeasurements,” for further discussion of the adoption of SFAS No. 157.

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Non-Trading Derivative Financial Instruments

The following table summarizes the fair values for outstanding derivative financial instruments used in EME’scontinuing operations for purposes other than trading, by risk category:

In millions December 31, 2008 2007

Commodity price:Electricity contracts $ 375 $ (137)

In assessing the fair value of EME’s non-trading derivative financial instruments, EME uses quoted marketprices and forward market prices adjusted for credit risk. The fair value of commodity price contracts takesinto account quoted market prices, time value of money, volatility of the underlying commodities and otherfactors. The increase in fair value of electricity contracts at December 31, 2008 as compared to December 31,2007 is attributable to a decline in the average market prices for power as compared to contracted prices atDecember 31, 2008, which is the valuation date. A 10% change in the market price at December 31, 2008would increase or decrease the fair value of outstanding derivative commodity price contracts byapproximately $59 million. The following table summarizes the maturities and the related fair value of EME’scommodity derivative assets and liabilities as of December 31, 2008:

In millionsTotal Fair

ValueMaturityG1 year

Maturity1 to 3years

Maturity4 to 5years

MaturityH5 years

Prices provided by externalsources $ 373 $ 232 $ 141 $ — $ —

Prices based on models and othervaluation methods 2 (1) 3 — —

Total $ 375 $ 231 $ 144 $ — $ —

Prices provided by external sources in the preceding table include derivatives whose fair value is based onforward market prices in active markets adjusted for non-performance risks which would be consideredLevel 2 derivative positions when there are no unobservable inputs that are significant to the valuation. EMEobtains forward market prices from traded exchanges (ICE Futures U.S. or New York Mercantile Exchange)and available broker quotes. Then, EME selects a primary source that best represents traded activity for eachmarket to develop observable forward market prices in determining the fair value of these positions. Brokerquotes or prices from exchanges are used to validate and corroborate the primary source. These pricequotations reflect mid-market prices (average of bid and ask) and are obtained from sources that EME believesto provide the most liquid market for the commodity. EME considers broker quotes to be observable whencorroborated with other information which may include a combination of prices from exchanges, other brokersand comparison to executed trades.

Energy Trading Derivative Financial Instruments

The fair value of the commodity financial instruments related to energy trading activities as of December 31,2008 and 2007 are set forth below:

In millions Assets Liabilities Assets Liabilities

December 31, 2008 December 31, 2007

Electricity contracts $ 282 $ 172 $ 141 $ 9Other 3 1 — —

Total $ 285 $ 173 $ 141 $ 9

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The change in the fair value of trading contracts for the year ended December 31, 2008 was as follows:

In millions

Fair value of trading contracts at January 1, 2008 $ 132Net gains from energy trading activities 171Amount realized from energy trading activities (182)Other changes in fair value (9)

Fair value of trading contracts at December 31, 2008 $ 112

A 10% change in the market price at December 31, 2008 would increase or decrease the fair value of tradingcontracts by approximately $2 million. The impact of changes to the various inputs used to determine the fairvalue of Level 3 derivatives is not currently material to EME’s results of operations as such changes are offsetby similar changes in derivatives classified within Level 3 as well as other categories.

The following table summarizes the maturities, the valuation method and the related fair value of energytrading assets and liabilities (as of December 31, 2008):

In millionsTotal Fair

ValueMaturityG1 year

Maturity1 to 3years

Maturity4 to 5years

MaturityH5 years

Prices activelyquoted $ 2 $ 3 $ (1) $ — $ —

Prices provided byexternal sources (102) (77) (23) (2) —

Prices based onmodels and othervaluation methods 212 109 64 31 8

Total $ 112 $ 35 $ 40 $ 29 $ 8

In the table above, prices actively quoted include exchange traded derivatives. Prices provided by externalsources include non-exchange traded derivatives which are priced based on forward market prices adjusted fornon-performance risks which would be considered Level 2 derivative positions when there are no unobservableinputs that are significant to the valuation. Fair values for Level 2 derivative positions are determined using thesame methodology previously described for non-trading derivative financial instruments. Fair value for Level 3derivative positions is determined using prices based on models and other valuation methods and include loadrequirements services contracts, illiquid financial transmission rights, over-the-counter derivatives at illiquidlocations and long-term power agreements. For long-term power agreements, EME’s subsidiary records theseagreements at fair value based upon a discounting of future electricity prices derived from a proprietary modelusing the risk free discount rate for a similar duration contract, adjusted for credit and liquidity.

Credit Risk

In conducting EME’s hedging and trading activities, EME contracts with a number of utilities, energycompanies, financial institutions, and other companies, collectively referred to as counterparties. In the event acounterparty were to default on its trade obligation, EME would be exposed to the risk of possible lossassociated with re-contracting the product at a price different from the original contracted price if the non-performing counterparty were unable to pay the resulting damages owed to EME. Further, EME would beexposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time acounterparty defaulted.

To manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measuredby the loss that EME would expect to incur if a counterparty failed to perform pursuant to the terms of its

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contractual obligations. EME measures, monitors and mitigates credit risk to the extent possible. To mitigatecredit risk from counterparties, master netting agreements are used whenever possible and counterparties maybe required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit orlower credit exposure.

EME has established processes to determine and monitor the creditworthiness of counterparties. EME managesthe credit risk of its counterparties based on credit ratings using published ratings of counterparties and otherpublicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide itin the process of setting credit levels, risk limits and contractual arrangements, including master nettingagreements. A risk management committee regularly reviews the credit quality of EME’s counterparties.Despite this, there can be no assurance that these efforts will be wholly successful in mitigating credit risk orthat collateral pledged will be adequate.

The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured asthe sum of net receivables (accounts receivable less accounts payable) and the current fair value of netderivative assets. EME’s subsidiaries enter into master agreements and other arrangements in conducting suchactivities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty.At December 31, 2008, the balance sheet exposure as described above, broken down by the credit ratings ofEME’s counterparties, was as follows:

Credit Rating(1) Exposure(2) CollateralNet

Exposure

In millions December 31, 2008

A or higher $ 379 $ (222) $ 157A- 62 — 62BBB+ 49 — 49BBB 132 1 133BBB- 51 — 51Below investment grade 10 (8) 2

Total $ 683 $ (229) $ 454

(1) EME assigns a credit rating based on the lower of a counterparty’s S&P orMoody’s rating. For ease of reference, the above table uses the S&P classificationsto summarize risk, but reflects the lower of the two credit ratings.

(2) Exposure excludes amounts related to contracts classified as normal purchase andsales and non-derivative contractual commitments that are not recorded on theconsolidated balance sheet, except for any related accounts receivable.

The credit risk exposure set forth in the above table is comprised of $203 million of net accounts receivableand payables and $481 million representing the fair value of derivative contracts. The exposure is based onmaster netting agreements with the related counterparties.

Included in the table above are exposures to financial institutions with credit ratings of A- or above. Due torecent developments in the financial markets, the credit ratings may not be reflective of the related credit risks.See “Edison International: Management Overview — Financial Markets and Economic Conditions” for furtherdiscussion. The total net exposure to financial institutions at December 31, 2008 was $151 million. This totalnet exposure excludes positions with Lehman Brothers Holdings and its subsidiaries. Five financial institutionscomprise 29% of the net exposure above with the largest single net exposure with a financial institutionrepresenting 11%. In addition to the amounts set forth in the above table, EME’s subsidiaries have posted an$88 million cash margin in the aggregate with PJM, NYISO, MISO, clearing brokers and other counterpartiesto support hedging and trading activities. Margining posted to support these activities also exposes EME tocredit risk of the related entities.

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EME’s plants owned by unconsolidated affiliates in which EME owns an interest sell power under powerpurchase agreements. Generally, each plant sells its output to one counterparty. Accordingly, a default by acounterparty under a power purchase agreement, including a default as a result of a bankruptcy, would likelyhave a material adverse effect on the operations of such power project.

In addition, coal for the Illinois Plants and the Homer City facilities is purchased from suppliers undercontracts which may be for multiple years. A number of the coal suppliers to the Illinois Plants and theHomer City facilities do not currently have an investment grade credit rating and, accordingly, EME may havelimited recourse to collect damages in the event of default by a supplier. EME seeks to mitigate this riskthrough diversification of its coal suppliers and through guarantees and other collateral arrangements whenavailable. Despite this, there can be no assurance that these efforts will be successful in mitigating credit riskfrom coal suppliers.

EME’s merchant plants sell electric power generally into the PJM market by participating in PJM’s capacityand energy markets or transact capacity and energy on a bilateral basis. Sales into PJM accounted forapproximately 50% of EME’s consolidated operating revenues for the year ended December 31, 2008.Moody’s rates PJM’s debt Aa3. PJM, an ISO with over 300 member companies, maintains its own credit riskpolicies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJMmember default are shared by all other members based upon a predetermined formula. At December 31, 2008,EME’s account receivable due from PJM was $61 million.

EME also derived a significant source of its revenues from the sale of energy, capacity and ancillary servicesgenerated at the Illinois Plants to Commonwealth Edison under load requirements services contracts. Salesunder these contracts accounted for 12% of EME’s consolidated operating revenues for the year endedDecember 31, 2008. Commonwealth Edison’s senior unsecured debt ratings are BBB- by S&P and Baa3 byMoody’s. At December 31, 2008, EME’s account receivable due from Commonwealth Edison was$23 million.

For the year ended December 31, 2008, a third customer, Constellation Energy Commodities Group, Inc.,accounted for 10% of EME’s consolidated operating revenues. Sales to Constellation are primarily generatedfrom EME’s merchant plants and largely consist of energy sales under forward contracts. The contract withConstellation is guaranteed by Constellation Energy Group, Inc., which has a senior unsecured debt rating ofBBB by S&P and Baa3 by Moody’s. At December 31, 2008, EME’s account receivable due fromConstellation was $22 million.

The terms of EME’s wind turbine supply agreements contain significant obligations of the suppliers in theform of manufacturing and delivery of turbines and payments, for delays in delivery and for failure to meetperformance obligations and warranty agreements. EME’s reliance on these contractual provisions is subject tocredit risks. Generally, these are unsecured obligations of the turbine manufacturer. A material adversedevelopment with respect to a turbine supplier may have a material impact on EME’s wind projects.

Edison Capital’s investments may be affected by the financial condition of other parties, the performance ofthe asset, economic conditions and other business and legal factors. Edison Capital generally does not controloperations or management of the projects in which it invests and must rely on the skill, experience andperformance of third party project operators or managers. These third parties may experience financialdifficulties or otherwise become unable or unwilling to perform their obligations. Edison Capital’s investmentsgenerally depend upon the operating results of a project with a single asset. These results may be affected bygeneral market conditions, equipment or process failures, disruptions in important fuel supplies or prices, oranother party’s failure to perform material contract obligations, and regulatory actions affecting utilitiespurchasing power from the leased assets. Edison Capital has taken steps to mitigate these risks in the structureof each project through contract requirements, warranties, insurance, collateral rights and default remedies, butsuch measures may not be adequate to assure full performance. In the event of default, lenders with a securityinterest in the asset may exercise remedies that could lead to a loss of some or all of Edison Capital’sinvestment in that asset.

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At December 31, 2008, Edison Capital had a net leveraged lease investment, before deferred taxes, of$50 million in three aircraft leased to American Airlines. American Airlines reported net losses during 2008and previously reported losses for a number of years prior to 2006. A default in the leveraged lease byAmerican Airlines could result in a loss of some or all of Edison Capital’s lease investment. At December 31,2008, American Airlines was current in its lease payments to Edison Capital.

Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investmentsin power projects. EMG mitigates the risk of interest rate fluctuations by arranging for fixed rate financing orvariable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for anumber of its project financings. Based on the amount of variable rate long-term debt for which EME has notentered into interest rate hedge agreements, a 100-basis-point change in interest rates at December 31, 2008would increase or decrease EME’s 2009 annual income before taxes by approximately $9 million. The fairmarket values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market valueof EMG’s consolidated long-term obligations (including current portion) was $4.1 billion at December 31,2008, compared to the carrying value of $4.8 billion. A 10% increase in market interest rates at December 31,2008 would result in a decrease in the fair value of EMG’s consolidated long-term obligations byapproximately $185 million. A 10% decrease in market interest rates at December 31, 2008 would result in anincrease in the fair value of EMG’s consolidated long-term obligations by approximately $203 million.

Other Risks

At December 31, 2008, Edison Capital had an investment balance of $33 million in three separate funds thatinvest in infrastructure assets in Latin America, Asia and countries in Europe with emerging economies and adirect investment of $2 million in one company in Latin America. For some fund investments, there may beforeign currency exchange rate risk. Edison Capital records its share of earnings from these investments on athree-month lag. Due to significant declines in global equity valuations since September 30, 2008, EdisonCapital is exposed to market to market losses of the underlying investments for period subsequent toSeptember 30, 2008. As Edison Capital has no ongoing equity contribution obligations, the maximumexposure to losses is equal to the amount of its investments.

Edison Capital’s cross-border leases are denominated in U.S. dollars and, therefore, are not exposed to foreigncurrency rate risk.

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EDISON INTERNATIONAL (PARENT)

EDISON INTERNATIONAL (PARENT): LIQUIDITY

The parent company’s liquidity and its ability to pay interest and principal on debt, if any, operating expensesand dividends to common shareholders are affected by dividends and other distributions from subsidiaries, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to bank and capitalmarkets. As a response to significant disruption in the credit and capital markets, Edison Internationalborrowed against its credit facility in September 2008. The proceeds were invested in U.S. treasury bills andU.S. treasury and government agency money market funds. At December 31, 2008, Edison International(parent) had approximately $320 million of cash and cash equivalents on hand.

On March 12, 2008, Edison International (parent) amended its existing $1.5 billion credit facility, extendingthe maturity to February 2013 while retaining existing borrowing costs as specified in the facility. Theamendment also provides four extension options which, if all exercised, and agreed to by lenders, will result ina final termination of February 2017.

A subsidiary of Lehman Brothers Holdings, Lehman Brothers Bank, FSB, is one of the lenders in EdisonInternational’s (parent) credit agreement representing a total commitment of $74 million. On September 15,2008, Lehman Brothers Holdings filed for protection under Chapter 11 of the U.S. Bankruptcy Code. LehmanBrothers Bank, FSB, fully funded $12 million of Edison International’s (parent) borrowing request, whichremains outstanding.

The following table summarizes the status of the Edison International (parent) credit facility at December 31,2008:

In millions

EdisonInternational

(parent)

Commitment $ 1,500Less: Unfunded commitment from Lehman Brothers subsidiary (62)

1,438Outstanding borrowings (250)Outstanding letters of credit —

Amount available $ 1,188

Edison International (parent)’s cash requirements for the 12-month period following December 31, 2008 areexpected to consist of:

• Dividends to common shareholders. The Board of Directors of Edison International declared a $0.31 pershare quarterly dividend in December 2008 which was paid in January 2009. This quarterly dividendrepresents an increase of $0.005 per share over dividends paid in 2008. The dividend increase is consistentwith Edison International’s dividend policy of paying out approximately 45% to 55% of the earnings ofSCE and balancing dividend increases with the significantly growing capital needs of Edison International’sbusiness;

• Maturity and interest payments on debt outstanding under the credit facility;

• Intercompany related debt; and

• General and administrative expenses.

Edison International (parent) expects to meet its 2009 continuing obligations through cash and cashequivalents on hand, external borrowings, tax-allocation payments under its tax-allocation agreements with its

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subsidiaries, and a $100 million SCE dividend paid in January 2009. Edison International does not expect toreceive further dividends from its subsidiaries in 2009.

EDISON INTERNATIONAL (PARENT): OTHER DEVELOPMENTS


Edison International files its federal income tax returns on a consolidated basis and files on a combined basisin California and certain other states. See “Other Developments — Federal and State Income Taxes” forfurther discussion of these matters.

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EDISON INTERNATIONAL (CONSOLIDATED)

RESULTS OF OPERATIONS AND HISTORICAL CASH FLOW ANALYSIS

Edison International’s reportable segments include its electric utility operations (SCE), nonutility powergeneration activities (EME), financial services and other (Edison Capital and EMG nonutility subsidiaries) andparent and other (includes amounts from Edison International (parent), other Edison International nonutilitysubsidiaries that are not significant as a reportable segment, as well as intercompany eliminations). Included inthe nonutility power generation segment are the activities of MEHC, the holding company of EME. MEHC’sonly substantive activities were its obligations under senior secured notes which were paid in full on June 25,2007. MEHC does not have any substantive operations.

In millions 2008 2007 2006

Electric utility $ 683 $ 707 $ 776EMG:

Nonutility power generation 501 340 344Financial services and other 60 70 88

Parent and other (29) (19) (27)

Edison International Net Income $ 1,215 $ 1,098 $ 1,181

Electric Utility Net Income

In millions 2008 2007 2006

Electric utility operating revenue $ 11,248 $ 10,233 $ 9,859

Fuel 1,400 1,191 1,112Purchased power 3,845 3,235 3,099Other operation and maintenance 3,245 3,055 2,843Depreciation, decommissioning and amortization 1,114 1,011 950Contract buyout/termination and other (9) — (1)

Total operating expenses 9,595 8,492 8,003

Operating income 1,653 1,741 1,856Interest and dividend income 22 44 58Other nonoperating income 101 89 85Interest expense – net of amount capitalized (407) (429) (399)Other nonoperating deductions (123) (45) (60)

Income from continuing operations before tax and minorityinterest 1,246 1,400 1,540

Income tax expense 342 337 438Dividends on preferred and preference stock of utility not subject to

mandatory redemption 51 51 51Minority interest 170 305 275

Income from continuing operations 683 707 776

Income (loss) from discontinued operations – net of tax — — —

Income before accounting change 683 707 776

Cumulative effect of accounting change – net of tax — — —

Electric Utility Net Income $ 683 $ 707 $ 776

SCE has variable interests in contracts with certain QFs that contain variable contract pricing provisions basedon the price of natural gas. Four of these contracts are with entities that are partnerships owned in part by

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EME. The QFs sell electricity to SCE and steam to nonrelated parties. As required by FIN 46(R), SCEconsolidates these Big 4 projects. See “— Nonutility power generation operating income” for a discussionrelated to the Big 4 projects.

Electric Utility Operating Revenue

The following table sets forth the major components of electric utility revenue:

In millions 2008 2007 2006

Electric utility revenueRetail billed and unbilled revenue $ 9,307 $ 9,213 $ 9,639Balancing account (over)/under collections 568 (270) (891)Sales for resale 580 489 369Big 4 projects (SCE’s VIEs)(1) 409 379 385Other (including intercompany transactions) 384 422 357

Total $ 11,248 $ 10,233 $ 9,859

(1) See “— Nonutility power generation operating income” for a discussion related to the Big 4projects.

SCE’s retail sales represented approximately 88%, 87% and 88% of electric utility revenue for the years endedDecember 31, 2008, 2007 and 2006, respectively. Due to warmer weather during the summer months andSCE’s rate design, electric utility revenue during the third quarter of each year is generally higher than otherquarters. Of total electric utility revenue, $6.7 billion, $5.3 billion, and $5.5 billion was used to collect costssubject to balancing account treatment in 2008, 2007 and 2006, respectively.

Total electric utility revenue increased by $1 billion in 2008 compared to 2007. The variances for the revenuecomponents are as follows:

• Retail billed and unbilled revenue increased $94 million in 2008, compared to the same period in 2007.The increase reflects a rate increase (including impact of tiered rate structure) of $92 million and a salesvolume increase of $2 million. The rate increase was due to minor variations of usage by rate class.

• SCE’s revenue requirement provides recovery of pass-through costs under ratemaking mechanisms(balancing accounts) authorized by the CPUC. The revenue requirement for pass-through costs providesrecovery of fuel and purchased-power expenses, demand-side management programs, nucleardecommissioning, public purpose programs, certain operation and maintenance expenses and depreciationexpense related to certain projects. SCE recognizes revenue equal to actual costs incurred for pass-throughcosts. In 2008, SCE accrued $568 million of revenue above the authorized revenue requirement comparedto a deferral of revenue of $270 million in 2007. The 2008 accrual is due to higher purchased power andfuel costs experienced during the year compared to levels authorized in rates (see “— Purchased-PowerExpense” and “— Fuel Expense” for further information).

• Sales for resale represent the sale of excess energy. Excess energy from SCE sources which may exist atcertain times is resold in the energy markets. Sales for resale revenue increased for 2008 due to higherexcess energy in 2008 compared to the same period in 2007, resulting from increased kWh purchases fromnew contracts, as well as increased sales from least cost dispatch energy. Revenue from sales for resale isrefunded to customers through the ERRA balancing account and does not impact earnings.

Total electric utility revenue increased by $374 million in 2007 compared to 2006 (as shown in the tableabove). The variances for the revenue components are as follows:

• Retail billed and unbilled revenue decreased $426 million in 2007, compared to the same period in 2006.The decrease reflects a rate decrease (including impact of tiered rate structure) of $545 million offset by asales volume increase of $119 million. Electric utility revenue from rate changes decreased mainly from

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the redesign of SCE’s tiered rate structure which resulted in a decrease of residential rates in the highertiers. Effective February 14, 2007, SCE’s system average rate decreased to 13.9¢ per-kWh (including 3.0¢per-kWh related to CDWR) mainly as the result of projected lower natural gas prices in 2007, as well asthe refund of overcollections in the ERRA balancing account that occurred in 2006 from lower thanexpected natural gas prices and higher than expected summer 2006 sales volume. Electric utility revenueresulting from sales volume changes was mainly due to customer growth as well as an increase in customerusage.

• SCE’s revenue requirement provides recovery of pass-through costs under ratemaking mechanisms(balancing accounts) authorized by the CPUC. The revenue requirement for pass-through costs providesrecovery of fuel and purchased-power expenses, demand-side management programs, nucleardecommissioning, public purpose programs, certain operation and maintenance expenses and depreciationexpense related to certain projects. SCE recognizes revenue equal to actual costs incurred for pass-throughcosts. In 2007, SCE deferred approximately $270 million compared to a deferral of approximately$891 million in 2006. The decrease in deferred revenue was mainly due to lower purchased power and fuelcosts experienced during 2007, compared to levels authorized in rates, resulting from warmer weather in2006 (see “— Purchased-Power Expense” and “— Fuel Expense” for further information).

• Electric utility revenue from sales for resale represents the sale of excess energy. Excess energy from SCEsources which may exist at certain times is resold in the energy markets. Sales for resale revenue increaseddue to higher excess energy in 2007, compared to 2006. Revenue from sales for resale is refunded tocustomers through the ERRA balancing account and does not impact earnings.

Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR toSCE’s customers, CDWR bond-related costs and a portion of direct access exit fees are remitted to the CDWRand are not recognized as revenue by SCE. The amounts collected and remitted to CDWR were $2.2 billion,$2.3 billion and $2.5 billion for the years ended December 31, 2008, 2007 and 2006, respectively.

Fuel Expense

In millions For The Year Ended December 31, 2008 2007 2006

SCE $ 587 $ 482 $ 389Big 4 projects (SCE’s VIEs)(1) 813 709 723

Total fuel expense $ 1,400 $ 1,191 $ 1,112

(1) See “— Nonutility Power Generation Operating Income” for information regarding the Big 4projects.

SCE’s fuel expense increased $105 million in 2008 and $93 million in 2007. The 2008 increase was mainlydue to an $85 million increase at SCE’s Mountainview plant resulting from higher gas costs in 2008. The2007 increase was mainly due to a $70 million increase at SCE’s Mountainview plant due to higher generationand higher gas costs in 2007; and a $20 million increase in nuclear fuel expense in 2007 resulting from highergeneration in 2007 due to a 2006 planned refueling and maintenance outage at SCE’s San Onofre Units 2and 3.

Purchased-Power Expense


Purchased-power $ 3,816 $ 3,179 $ 2,940Realized losses on economic hedging activities – net 60 132 339Energy settlements and refunds (31) (76) (180)

Total purchased-power expense $ 3,845 $ 3,235 $ 3,099

SCE’s total purchased-power expense increased $610 million in 2008 and $136 million in 2007.

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Purchased-power, in the table above, increased $637 million in 2008 and $239 million in 2007. The 2008increase was due to: higher bilateral energy purchases of $360 million, resulting from higher costs per kWhdue to higher gas prices and increased kWh purchases; higher QF purchased-power expense of $135 million,resulting from increased kWh purchases and an increase in the average spot natural gas prices for certaincontracts; and higher ISO-related energy costs of $165 million. These increases were partially offset by$30 million of lower firm transmission rights costs. The 2007 increase was due to higher bilateral energypurchases of $230 million, resulting from higher costs per kWh and increased kWh purchases from newcontracts entered into in 2007; higher QF purchased-power expense of $105 million, resulting from anincrease in the average spot natural gas prices (as discussed further below); and higher firm transmission rightcosts of $50 million. The 2007 increase was partially offset by a decrease in ISO-related energy costs of$150 million.

SCE’s realized gains and losses arising from derivative instruments are reflected in purchased-power expenseand are recovered through the ERRA mechanism. Unrealized gains and losses have no impact on purchased-power expense due to regulatory mechanisms. As a result, realized and unrealized gains and losses do notaffect earnings, but may temporarily affect cash flows. Realized losses on economic hedging were $60 millionin 2008, $132 million in 2007, and $339 million in 2006. Unrealized (gains) losses on economic hedging were$638 million in 2008, $(91) million in 2007, and $237 million in 2006. Changes in realized and unrealizedgains and losses on economic hedging activities were primarily due to significant decreases in forward naturalgas prices in 2008 compared to 2007. Changes in realized and unrealized gains and losses on economichedging activities in 2007 compared to 2006 were primarily due to changes in SCE’s gas hedge portfolio mixas well as an increase in the natural gas futures market in 2007. (See “SCE: Market Risk Exposures —Commodity Price Risk” for further discussion).

SCE received energy settlements and refunds (including generator settlements) of $31 million in 2008,$76 million in 2007 and $180 million in 2006. Certain of these refunds are from sellers of electricity andnatural gas who manipulated the electric and natural gas markets during the energy crisis in California in2000 – 2001 or who benefited from the manipulation by receiving inflated market prices. SCE is required torefund to customers 90% of any refunds actually realized by SCE for these types of refunds, net of litigationcosts, and 10% will be retained by SCE as a shareholder incentive.

Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated prices. Energy payments to gas-fired QFs are generally tied to spot natural gas prices. Energypayments for most renewable QFs are at a fixed price of 5.37¢ per-kWh. In late 2006, certain renewable QFcontracts were amended and energy payments for these contracts are at a fixed price of 6.15¢ per-kWh,effective May 2007.

Other Operation and Maintenance Expense

SCE’s other operation and maintenance expense increased $190 million in 2008 and increased $212 million in2007. Other operating and maintenance expenses related to regulatory balancing accounts increased$70 million in 2008 compared to 2007, mainly related to higher demand-side management costs and energyefficiency costs. These accounts are recovered through regulatory mechanisms approved by the CPUC and donot impact earnings. The increase in operation and maintenance expense in 2008 also reflects: higheradministrative and general costs of $35 million; higher generation expenses of $60 million related tomaintenance and refueling outage expenses at San Onofre and higher overhaul and outage costs at FourCorners and Palo Verde; higher generation expenses of $20 million at Mountainview; and higher customerservice costs of $15 million; and higher employer payroll taxes and property taxes of $15 million. The 2008variance also reflects a decrease of approximately $30 million related to lower transmission and distributionmaintenance costs. The 2007 increase reflects $98 million of higher costs associated with certain operationand maintenance expense accounts recovered through regulatory mechanisms approved by the CPUC. Thesecosts were mainly related to both higher demand-side management and energy efficiency costs partially offsetby lower must-run and must-offer obligation costs related to the reliability of the ISO systems. The 2007

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increase was also due to higher transmission and distribution maintenance costs of approximately $20 million;higher health care costs and other benefits of $30 million; higher generation expenses of $20 million atMountainview; higher uncollectible accounts of $10 million; and higher legal costs of $20 million. The 2007increase was partially offset by lower generation-related costs of approximately $20 million in 2007 resultingfrom the planned refueling and maintenance outages at SCE’s San Onofre Units 2 and 3 in the first quarter of2006.

Depreciation, Decommissioning and Amortization Expense

SCE’s depreciation, decommissioning and amortization expense increased $103 million in 2008 and increased$61 million in 2007. The 2008 increase was primarily due to $90 million increased depreciation resulting fromadditions to transmission and distribution assets (see “SCE: Liquidity — Capital Expenditures” for a furtherdiscussion); and a $17 million cumulative depreciation rate adjustment recorded in the second quarter of 2008.The 2007 increase was primarily due to $50 million increased depreciation resulting from additions totransmission and distribution asset additions (see “SCE: Liquidity — Capital Expenditures” for a furtherdiscussion).

Interest Income

SCE’s interest income decreased $22 million in 2008 and $14 million in 2007. The 2008 and 2007 decreaseswere mainly due to lower undercollection balances in certain balancing accounts and lower interest ratesapplied to those undercollections.

Other Nonoperating Income

SCE’s other nonoperating income increased $12 million in 2008. The 2008 increase was due to receipt ofcorporate-owned life insurance proceeds and an increase in allowance for funds used during construction –equity resulting from an increase in construction work in progress due to planned capital expenditures (seeSCE: Liquidity — Capital Expenditures” for further discussion). The increase was partially offset by paymentsreceived in the third quarter of 2007 for settlement of claims related to the natural gas purchased contracts forone of SCE’s VIE projects.

Interest Expense – Net of Amounts Capitalized

SCE’s interest expense – net of amounts capitalized decreased $22 million in 2008 and increased $30 millionin 2007. The 2008 decrease was mainly due to lower over-collections of certain balancing accounts and lowerinterest rates applied to those over-collections during 2008, compared to 2007. This 2008 decrease waspartially offset by higher interest expense on short-term debt and long-term debt resulting from higherbalances compared to the same period in 2007. The 2007 increase was mainly due to higher interest expenseon balancing account overcollections in 2007, as compared to 2006, and higher interest expense on long-termdebt resulting from higher balances outstanding during 2007, as compared to 2006.

Other Nonoperating Deductions

SCE’s other nonoperating deductions increased $78 million in 2008 and decreased $15 million in 2007. The2008 increase primarily resulted from a CPUC decision in September 2008 related to SCE incentives claimedunder a CPUC-approved PBR mechanism. The decision required SCE to refund $28 million and $20 millionrelated to customer satisfaction and employee safely reporting incentives, respectively, and further requiredSCE to forego claimed incentives of $20 million and $15 million related to customer satisfaction andemployee safety reporting, respectively. The decision also required SCE to refund $33 million for employeebonuses related to the program and imposed a statutory penalty of $30 million. During the third quarter of2008, SCE recorded a charge of $49 million, after-tax ($60 million, pre-tax) in the consolidated statements ofincome related to this decision. The 2008 increase in other nonoperating deductions was also due to

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approximately $10 million for expenditures related to civic, political and related activities, and donations. The2007 decrease was mainly due to a penalty accrual of $23 million under the customer satisfaction performancemechanism discussed above which was recognized in 2006.

Income Taxes

The composite federal and state statutory income tax rate was approximately 40% (net of the federal benefitfor state income taxes) for all periods presented. The lower effective tax rate of 31.8% realized in 2008 ascompared to the statutory rate was primarily due to software and property related flow through deductions.The lower effective tax rate of 30.8% realized in 2007 as compared to the statutory rate was primarily due toreductions made to the income tax reserve to reflect progress made in an administrative appeals process withthe IRS related to the income tax treatment of certain costs associated with environmental remediation and toreflect an audit settlement of state tax issues. The lower effective tax rate of 34.6% realized in 2006 ascompared to the statutory rate was primarily due to a settlement reached with the California Franchise TaxBoard regarding a state apportionment issue partially offset by tax reserve accruals.

Nonutility Power Generation Net Income

The following table sets forth the major changes in nonutility power generation net income:

In millions 2008 2007 2006

Nonutility power generation operating revenue $ 2,811 $ 2,580 $ 2,239

Fuel 747 684 645Other operation and maintenance 1,004 969 827Depreciation, decommissioning and amortization 194 162 144Contract buyout/termination and other 14 1 —


Operating income 852 764 623Interest and dividend income 36 98 98Equity in income from partnerships and unconsolidated

subsidiaries – net 122 200 186Other nonoperating income 12 6 26Interest expense – net of amounts capitalized (279) (313) (393)Other nonoperating deductions — — (3)Loss on early extinguishment of debt — (241) (146)

Income from continuing operations before tax and minorityinterest 743 514 391

Income tax expense 243 173 145

Minority interest — (1) (1)


Income (loss) from discontinued operations – net of tax 1 (2) 97



Net income $ 501 $ 340 $ 344

Nonutility Power Generation Operating Income

EME operates in one line of business, independent power production. Operating revenues are primarilyderived from the sale of energy and capacity from the Illinois Plants and the Homer City facilities. Equity in

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income from unconsolidated affiliates primarily relates to energy projects accounted for under the equitymethod. EME recognizes its proportional share of the income or loss of such entities.

EME uses the words “earnings” or “losses” in this section to describe adjusted operating income (loss) asdescribed below.

The following section and table provides a summary of results of EME’s operating projects and corporateexpenses for the three years ended December 31, 2008, together with discussions of the contributions byspecific projects and of other significant factors affecting these results. EME has modified its internalreporting of project profitability using a new performance measure entitled adjusted operating income.Previously, EME used pre-tax income adjusted for production tax credits to measure the profitability ofprojects. The change in measurement to adjusted operating income was made to improve the comparison ofperformance excluding financing costs which may be at different entities throughout the corporate hierarchy,but do not affect the operating profitability of a project.

The following table shows the adjusted operating income of EME’s projects:

In millions 2008 2007 2006

Illinois Plants $ 688 $ 583 $ 463Homer City 202 221 150Renewable energy projects 59 30 19Energy trading 164 142 130Big 4 projects 87 147 136Sunrise 24 33 34Westside projects 9 11 11Doga 8 14 —Other non-wind projects 14 14 6Other (31) (7) 11

1,224 1,188 960Corporate administrative and general (172) (169) (108)Corporate depreciation and amortization (12) (8) (4)

Adjusted Operating Income(1) $ 1,040 $ 1,011 $ 848

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The following table reconciles adjusted operating income to operating income as reflected on EME’sconsolidated statements of income:

In millions 2008 2007 2006

Adjusted Operating Income $ 1,040 $ 1,011 $ 848Less:

Equity in earnings of unconsolidated affiliates 122 200 186Dividend income from projects 10 12 2Production tax credits 44 29 16Other income (expense), net 12 6 21

Operating Income $ 852 $ 764 $ 623

(1) Adjusted operating income is equal to operating income under GAAP, plus equity inearnings of unconsolidated affiliates, dividend income from projects, production taxcredits and other income and expenses. Production tax credits are recognized as windenergy is generated based on a per-kilowatt-hour rate prescribed in applicable federaland state statutes. Adjusted operating income is a non-GAAP performance measure andmay not be comparable to those of other companies. Management believes thatinclusion of earnings of unconsolidated affiliates, dividend income from projects,production tax credits and other income and expenses in adjusted operating income ismore meaningful for investors as these components are integral to the operating resultsof EME.

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Illinois Plants

The following table presents additional data for the Illinois Plants:

In millions 2008 2007 2006

Operating Revenues $ 1,778 $ 1,579 $ 1,399Operating Expenses

Fuel(1) 482 400 382Gain on sale of emission allowances(2) (3) (18) (16)Plant operations 434 420 369Plant operating leases 75 75 75Depreciation and amortization 106 99 101(Gain) on buyout of contract and (gain) loss on sale of assets (16) — 4Administrative and general 22 22 19

Total operating expenses 1,100 998 934

Operating Income 678 581 465Other Income (Expense) 10 2 (2)

Adjusted Operating Income(3) $ 688 $ 583 $ 463

StatisticsGeneration (in GWh):

Energy only contracts 26,010 22,503 28,898Load requirements services contracts(4) 5,090 7,458 —

Total 31,100 29,961 28,898

Aggregate plant performance:Equivalent availability(5) 81.0% 75.8% 79.3%Capacity factor(6) 64.8% 60.9% 58.8%Load factor(7) 80.0% 80.4% 74.1%Forced outage rate(8) 8.3% 9.7% 7.9%

Average realized price/MWh:Energy only contracts(9) $ 51.82 $ 48.79 $ 46.19Load requirements services contracts(10) $ 62.64 $ 63.43 $ —

Capacity revenue only (in millions) $ 111 $ 27 $ 24Average fuel costs/MWh $ 15.49 $ 13.36 $ 13.19

(1) The Illinois Plants purchased NOX emission allowances from the Homer City facilities at fair marketvalue. Purchases were $0.4 million in 2007 and $6 million in 2006. These purchases are included in fuelcosts. There were no purchases in 2008.

(2) The Illinois Plants sold excess SO2 emission allowances to the Homer City facilities at fair market value.Sales to the Homer City facilities were $2 million in 2008, $21 million in 2007 and $14 million in 2006.These sales reduced operating expenses. EME recorded $3 million of intercompany profit during 2008consisting of $1 million and $2 million on emission allowances sold by the Illinois Plants to the HomerCity facilities during the first quarter of 2008 and the fourth quarter of 2007, respectively, but not yet usedby the Homer City facilities until the second quarter of 2008 and the first quarter of 2008, respectively. Inaddition, EME recorded $4 million of intercompany profit during 2007 that was eliminated by EME in2006 on emission allowances sold by the Illinois Plants to the Homer City facilities in the fourth quarterof 2006 but not used by the Homer City facilities until the first quarter of 2007. EME recorded $6 millionof intercompany profit during the first quarter of 2006 that was eliminated by EME in 2005 on emissionallowances sold by the Illinois Plants to the Homer City facilities in the fourth quarter of 2005 but notused by the Homer City facilities until the first quarter of 2006.

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(3) As described above, adjusted operating income is equal to operating income plus other income (expense).Adjusted operating income is a non-GAAP performance measure and may not be comparable to those ofother companies. Management believes that inclusion of other income (expense) is more meaningful forinvestors as the components of other income (expense) are integral to the results of the Illinois Plants.

(4) Represents two load requirements services contracts, awarded as part of an Illinois auction, withCommonwealth Edison that commenced on January 1, 2007, one of which expired in May 2008 and theremaining contract is scheduled to expire in May 2009.

(5) The equivalent availability factor is defined as the number of MWh the coal plants are available togenerate electricity divided by the product of the capacity of the coal plants (in MW) and the number ofhours in the period. Equivalent availability reflects the impact of the unit’s inability to achieve full load,referred to as derating, as well as outages which result in a complete unit shutdown. The coal plants arenot available during periods of planned and unplanned maintenance.

(6) The capacity factor is defined as the actual number of MWh generated by the coal plants divided by theproduct of the capacity of the coal plants (in MW) and the number of hours in the period.

(7) The load factor is determined by dividing capacity factor by the equivalent availability factor.(8) Midwest Generation refers to unplanned maintenance as a forced outage.(9) The average realized energy price reflects the average price at which energy is sold into the market

including the effects of hedges, real-time and day-ahead sales and PJM fees and ancillary services. It isdetermined by dividing (i) operating revenue less unrealized SFAS No. 133 gains (losses) and other non-energy related revenue by (ii) generation as shown in the table below. Revenue related to capacity salesare excluded from the calculation of average realized energy price.


Operating revenues $ 1,778 $ 1,579 $ 1,399Less:

Load requirements services contracts (319) (473) —Unrealized losses (gains) 6 25 (30)Capacity and other revenues (117) (33) (34)

Realized revenues $ 1,348 $ 1,098 $ 1,335

Generation (in GWh) 26,010 22,503 28,898Average realized energy price/MWh $ 51.82 $ 48.79 $ 46.19

(10) The average realized price reflects the contract price for sales to Commonwealth Edison under loadrequirements services contracts that include energy, capacity and ancillary services. It is determined bydividing (i) contract revenue less PJM operating and ancillary charges by (ii) generation.

Earnings from the Illinois Plants increased $105 million in 2008 compared to 2007, and $120 million in 2007compared to 2006. The 2008 increase in earnings was primarily attributable to higher realized gross margin,an increase in unrealized gains related to hedge contracts (described below) and a $15 million gain recordedduring the first quarter of 2008 related to a buyout of a fuel contract. See “Commitments, Guarantees andIndemnities — Fuel Supply Contracts” for further discussion. The increase in realized gross margin was due toan increase in capacity prices as a result of the PJM RPM auction. The increase in generation and slightlyhigher average realized energy prices was partially offset by higher coal and transportation costs. The 2008increase in earnings was also partially offset by a $24 million charge related to power contracts due to thebankruptcy of Lehman Brothers Holdings described below.

Two factors are expected to increase operating expenses by approximately $90 million to $105 million during2009 as compared to 2008:

• Effective January 1, 2009, the CAIR requires Midwest Generation to purchase annual NOX allowances inexcess of the amounts allocated by the state of Illinois under its SIP. See “Other Developments —

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Environmental Matters — Air Quality Regulation — Clean Air Interstate Rule — Illinois” for furtherdiscussion.

• Midwest Generation installed activated carbon injection equipment to reduce mercury emissions at theIllinois Plants.

The 2007 increase in earnings was primarily attributable to higher energy revenues resulting from higheraverage realized energy prices and slightly higher generation as compared to 2006. Partially offsetting theseincreases were higher planned maintenance costs, unplanned outages at the Powerton Station and a$7.5 million payment during the third quarter of 2007 related to the settlement agreement with the IllinoisAttorney General. Earnings were also adversely affected by an increase in unrealized losses in 2007 related topower contracts described below.

Included in operating revenues were unrealized gains (losses) of $(6) million, $(25) million and $30 million in2008, 2007 and 2006, respectively. In 2008, unrealized losses included $24 million from power contracts for2009 and 2010 with Lehman Brothers Commodity Services, Inc. These contracts qualified as cash flow hedgesunder SFAS No. 133 until EME dedesignated the contracts due to non-performance risk and subsequentlyterminated the contracts. The change in fair value was recorded as an unrealized loss during 2008. Unrealizedgains (losses) were also attributable to the ineffective portion of forward and futures contracts which arederivatives that qualify as cash flow hedges under SFAS No. 133 and power contracts that did not qualify forhedge accounting under SFAS No. 133 (sometimes referred to as economic hedges). These energy contractswere entered into to hedge the price risk related to projected sales of power. During 2007, power pricesincreased, resulting in mark-to-market losses on economic hedges. See “EMG: Market Risk Exposures —Commodity Price Risk” and “EMG: Market Risk Exposures — Accounting for Energy Contracts” for moreinformation regarding forward market prices and the write-off of the power contracts, respectively.

Powerton Station Outage —

On December 18, 2007, Unit 6 at the Powerton Station had a duct failure resulting in a suspension ofoperations at this unit through February 12, 2008. Scheduled maintenance work for the spring of 2008 wasaccelerated to minimize the aggregate impact of the outage. The duct failure resulted in claims under MidwestGeneration’s property and business interruption insurance policies. During the first quarter of 2008, $6 millionrelated to business interruption insurance coverage was recorded primarily related to these claims reflected inother nonoperating income on Edison International’s consolidated statements of income. At December 31,2008, Midwest Generation had a $4 million receivable recorded related to these claims.

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Homer City

The following table presents additional data for the Homer City facilities:

In millions 2008 2007 2006

Operating Revenues $ 717 $ 764 $ 642Operating Expenses

Fuel(1) 270 306 283Gain on sale of emission allowances(2) — — (7)Plant operations 126 119 106Plant operating leases 102 102 102Depreciation and amortization 16 14 16Administrative and general 4 4 5

Total operating expenses 518 545 505

Operating Income 199 219 137Other Income 3 2 13


StatisticsGeneration (in GWh) 11,334 13,649 12,286Equivalent availability(4) 80.7% 89.4% 81.9%Capacity factor(5) 68.3% 82.5% 74.3%Load factor(6) 84.6% 92.4% 90.7%Forced outage rate(7) 9.8% 4.1% 13.5%Average realized energy price/MWh(8) $ 56.24 $ 54.40 $ 48.02Capacity revenue only (in millions) $ 46 $ 30 $ 16Average fuel costs/MWh $ 23.35 $ 22.45 $ 23.05

(1) The Homer City facilities purchased SO2 emission allowances from the Illinois Plants at fairmarket value. Purchases were $2 million in 2008, $21 million in 2007 and $14 million in2006. These purchases are included in fuel costs.

(2) The Homer City facilities sold excess NOx emission allowances to the Illinois Plants at fairmarket value. Sales to the Illinois Plants were $0.4 million in 2007 and $6 million in 2006.There were no sales in 2008. The 2007 and 2006 sales reduced operating expenses. Inaddition, EME recorded a $1 million intercompany profit during 2006, eliminated in 2005,on emission allowances sold by the Homer City facilities to the Illinois Plants but not usedby the Illinois Plants until 2006.

(3) As described above, adjusted operating income is equal to operating income plus otherincome. Adjusted operating income is a non-GAAP performance measure and may not becomparable to those of other companies. Management believes that inclusion of otherincome is more meaningful for investors as the components of other income are integral tothe results of the Homer City facilities.

(4) The equivalent availability factor is defined as the number of MWh the coal plants areavailable to generate electricity divided by the product of the capacity of the coal plants (inMW) and the number of hours in the period. Equivalent availability reflects the impact ofthe unit’s inability to achieve full load, referred to as derating, as well as outages whichresult in a complete unit shutdown. The coal plants are not available during periods ofplanned and unplanned maintenance.

(5) The capacity factor is defined as the actual number of MWh generated by the coal plantsdivided by the product of the capacity of the coal plants (in MW) and the number of hoursin the period.

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(6) The load factor is determined by dividing capacity factor by the equivalent availabilityfactor.

(7) Homer City refers to unplanned maintenance as a forced outage.(8) The average realized energy price reflects the average price at which energy is sold into the

market including the effects of hedges, real-time and day-ahead sales and PJM fees andancillary services. It is determined by dividing (i) operating revenue less unrealizedSFAS No. 133 gains (losses) and other non-energy related revenue by (ii) total generation asshown in the table below. Revenue related to capacity sales are excluded from thecalculation of average realized energy price.


Operating revenues $ 717 $ 764 $ 642Less:

Unrealized losses (gains) (21) 10 (35)Capacity and other revenues (59) (31) (17)

Realized revenues $ 637 $ 743 $ 590

Generation (in GWh) 11,334 13,649 12,286Average realized energy price/MWh $ 56.24 $ 54.40 $ 48.02

Earnings from Homer City decreased $19 million in 2008 compared to 2007 and increased $71 million in2007 compared to 2006. The 2008 decrease in earnings was primarily attributable to lower realized grossmargin and higher plant maintenance expenses, partially offset by an increase in unrealized gains related tohedge contracts (described below). The decline in realized gross margin was primarily due to lower generationfrom higher forced outages, lower off-peak dispatch and extended planned overhauls in 2008, partially offsetby an increase in capacity revenues and the sale of excess coal inventory. Included in fuel costs were$19 million, $31 million and $35 million in 2008, 2007 and 2006, respectively, related to the net cost of SO2

emission allowances. See “Market Risk Exposures — Commodity Price Risk — Emission Allowances PriceRisk” for more information regarding the price of SO2 allowances.

The 2007 increase in earnings was primarily attributable to an increase in energy revenues from highergeneration and average realized energy prices, and an increase in capacity revenues resulting from the PJMRPM auction. Partially offsetting these increases were higher maintenance costs in 2007 related to the plannedoutage at Unit 2 of the Homer City facilities and lower other income in 2007 for the estimated insurancerecovery related to the Unit 3 outage of approximately $3 million recorded during the third quarter of 2007,compared to approximately $11 million recorded during the second quarter of 2006, reflected in other income(expense), net on EME’s consolidated statements of income. Earnings for 2007 were also adversely affecteddue to the timing of unrealized gains and losses related to hedge contracts discussed below.

Included in operating revenues were unrealized gains (losses) from hedge activities of $21 million,$(10) million and $35 million in 2008, 2007 and 2006, respectively. Unrealized gains (losses) were primarilyattributable to the ineffective portion of forward and futures contracts which are derivatives that qualify ascash flow hedges under SFAS No. 133. The ineffective portion of hedge contracts at Homer City wasprimarily attributable to changes in the difference between energy prices at PJM West Hub (the settlementpoint under forward contracts) and the energy prices at the Homer City busbar (the delivery point wherepower generated by the Homer City facilities is delivered into the transmission system). See “EMG: MarketRisk Exposures — Commodity Price Risk” and “EMG: Market Risk Exposures — Accounting for EnergyContracts” for more information regarding forward market prices and unrealized gains (losses), respectively.

The average realized energy price received by Homer City in 2008, 2007 and 2006 was $56.24/MWh,$54.40/MWh and $48.02/MWh, respectively, compared to the average real-time market price at the HomerCity busbar for the same periods of $57.72/MWh, $51.03/MWh and $45.15/MWh, respectively. The averagerealized energy price for the twelve months ended December 31, 2008 was below the 24-hour PJM average

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market price at the Homer City busbar primarily due to effective hedge prices being below market prices forthe same period. Homer City’s average realized energy price varies from the average real-time market pricedue to: (1) hedge contracts having been entered into in prior periods, (2) differences between market pricesduring periods of actual generation (generally weighted to on-peak periods) and the 24-hour average real-timemarket prices, and (3) changes in the differential in market prices at the PJM West Hub versus the Homer Citybusbar. The increase in the differential is referred to as a widening of the basis between these PJM locations.Homer City hedges its energy price risk at PJM West Hub and retains the risk that the basis between PJMWest Hub and Homer City widens. See “EMG: Market Risk Exposures — Commodity Price Risk — BasisRisk” and “Market Risk Exposures — Accounting for Energy Contracts.”

Seasonal Disclosure

Due to higher electric demand resulting from warmer weather during the summer months and cold weatherduring the winter months, electric revenue from the Illinois plants and the Homer City facilities varysubstantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods oflower projected electric demand (spring and fall) further reducing generation and increasing majormaintenance costs which are recorded as an expense when incurred. Accordingly, earnings from the Illinoisplants and the Homer City facilities are seasonal and have significant variability from quarter to quarter.Seasonal fluctuations may also be affected by changes in market prices. See “EMG: Market RiskExposures — Commodity Price Risk — Energy Price Risk Affecting Sales from the Illinois Plants” and“— Energy Price Risk Affecting Sales from the Homer City Facilities” for further discussion regarding marketprices.

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Renewable Energy Projects

The following table presents additional data for EME’s renewable energy projects:

In millions 2008 2007 2006

Operating Revenues $ 108 $ 51 $ 30Production Tax Credits 44 29 16

152 80 46

Operating ExpensesPlant operations 35 18 12Depreciation and amortization 59 34 20Administrative and general 2 1 —

Total operating expenses 96 53 32

Other Income 3 3 5


StatisticsGeneration (in GWh) 2,286 1,533 897Aggregate plant performance:

Equivalent availability 80.4% 85.5% 96.1%Capacity factor 33.1% 37.8% 34.1%

(1) Adjusted operating income is equal to operating income (loss) plus production taxcredits and other income. Production tax credits are recognized as wind energy isgenerated based upon a per-kilowatt-hour rate prescribed in applicable federal andstate statutes. Under GAAP, production tax credits generated by wind projects arerecorded as a reduction in income taxes. Accordingly, adjusted operating incomerepresents a non-GAAP performance measure which may not be comparable tothose of other companies. Management believes that inclusion of production taxcredits in adjusted operating income for wind projects is more meaningful forinvestors as federal and state subsidies are an integral part of the economics ofthese projects. The following table reconciles adjusted operating income as shownabove to operating income (loss) under GAAP:


Adjusted Operating Income $ 59 $ 30 $ 19Less:

Production tax credits 44 29 16Other income 3 3 5

Operating Income (Loss) $ 12 $ (2) $ (2)

EME has significantly expanded its renewable energy project portfolio during the past three years. EME’sshare of installed capacity of new wind projects that commenced operations during 2008 and 2007 was396 MW and 292 MW, respectively. New projects that commenced operations were the primary drivers forincreases in the revenues and operating costs and adjusted operating income.

EME’s operating wind projects include 189 turbines manufactured by Suzlon Wind Energy Corporation(Suzlon). Rotor blade cracks were identified on certain of the Suzlon Model S88 wind turbines using V-2blades, and Suzlon has advised EME that such cracks have also appeared on turbines with another Suzloncustomer. Suzlon, with review and oversight from EME’s technical experts, has completed its analysis andblade testing to determine the root cause of the blade crack issues and a remediation plan is beingimplemented. To address the commercial impact of these issues on EME and its projects, during the second

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quarter of 2008, EME signed an agreement with Suzlon providing EME with enhanced warranty and creditprotections with respect to the Suzlon turbine issues including the rotor blade crack issues. The availabilityand capacity factors were adversely affected due to performance issues with the Suzlon turbines. However,under the terms of the turbine supply agreements, Suzlon has agreed to provide liquidated damages forunavailability of turbines. Revenues recognized for liquidated damages were $28 million in 2008 (of which$4 million related to 2007 generation).

In addition to the Suzlon turbines, EME has purchased 71 turbines from Clipper Turbine Works, Inc. (Clipper)of which 20 turbines are in service at the Jeffers wind project and 40 turbines are planned for the HighLonesome wind project currently under construction. EME recently learned that problems have beendiscovered in the blades on certain Clipper wind turbines. Root cause analysis to date has determined theblade problems resulted from a manufacturing defect. During the fourth quarter of 2008, EME signed anagreement with Clipper addressing procedures for remediation, enhanced warranties, and other protectionswith respect to the blades planned for the High Lonesome wind project. EME and Clipper are currentlydiscussing a similar agreement with respect to the blades in service at the Jeffers project. EME expects tocontinue to work with Clipper to review the root cause analysis of the blade problems and necessary correctiveactions, and to address commercial matters that result from the impact of these issues on its projects.

Energy Trading

EME seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities in thosemarkets in which it is active as a result of its management of the merchant power plants of MidwestGeneration and Homer City. EMMT trades power, fuel, and transmission congestion primarily in the easternpower grid using products available over the counter, through exchanges, and from ISOs. Earnings fromenergy trading activities were $164 million, $142 million and $130 million in 2008, 2007 and 2006,respectively. The 2008 increase in earnings from energy trading activities was primarily attributable toincreased congestion and market volatility in key markets and gains from the Maryland contracts describedbelow. The 2007 increase in earnings from energy trading activities was primarily attributable to increasedcongestion and market volatility in key markets and higher earnings from energy trading in theover-the-counter markets.

In April 2008, EMMT entered into three load services requirements contracts in Maryland with local utilities.Under the terms of the load services requirements contracts, EMMT is obligated to supply a portion of eachutility’s load at fixed prices that vary based on periods specified in the contracts. EMMT is obligated to payfor the cost of supply at each utility’s load zones including, energy, capacity, ancillary services and renewableenergy credits. The estimated load for the period of January 1, 2009 through September 30, 2010 isapproximately 3.9 million MWh. EMMT has entered into futures contracts to substantially hedge the energyprice risk related to these contracts. The above contracts are recorded as derivatives with the change in fairvalue reflected in trading income above.

Earnings from Unconsolidated Affiliates

Big 4 Projects

EME owns partnership investments (50% ownership or less) in Kern River Cogeneration Company, Midway-Sunset Cogeneration Company, Sycamore Cogeneration Company and Watson Cogeneration Company. Theseprojects were used, collectively, to secure financing by Edison Mission Energy Funding Corp., a specialpurpose entity. The Edison Mission Energy Funding Corp. financing was paid in full in September 2008. Dueto similar economic characteristics, EME evaluates these projects collectively and refers to them as the Big 4projects.

Earnings from the Big 4 projects decreased $60 million in 2008 compared to 2007, and increased $11 millionin 2007 compared to 2006. The 2008 decrease in earnings was primarily due to $60 million in lower earningsfrom the Sycamore and Watson projects as a result of lower pricing in 2008 than previously applied under a

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long-term power sales agreement that expired. Two of EME’s Big 4 projects (the Sycamore project and theWatson project) have power purchase agreements with SCE that have transitioned, or are in the process oftransitioning, to new pricing terms. Under FIN 46(R), Edison International and SCE consolidate these projectsdue to SCE’s variable interest in these entities. The Sycamore project’s long-term contract with SCE expiredon December 31, 2007. SCE contends that its long-term power purchase agreement with the Watson projectalso expired on December 31, 2007. The Watson project contends that the agreement expired in April 2008.The two projects are currently selling electricity to SCE under terms and conditions contained in their priorlong-term power purchase agreements with revised pricing terms as mandated by the CPUC. EdisonInternational expects that this arrangement will eventually be replaced by a new power purchase agreementbetween Watson and SCE, but cannot predict at this time whether or when this will occur. Any reduced coststo SCE resulting from these discussions will not impact SCE earnings because the savings flow through theregulatory recovery process to customers.

The 2007 change in earnings was primarily due to payments received in settlement of claims related to thenatural gas purchase contracts during the second quarter of 2007 and outages at the Sycamore Cogenerationplant in 2006. Partially offsetting these increases were lower volumes sold in 2007 for the Kern River project.

The power sales agreement of the Midway-Sunset project is scheduled to expire in May 2009. Thereafter,Midway-Sunset expects to continue selling electricity either pursuant to a new power sales agreement or toSCE under the terms and conditions contained in its prior long-term power sales agreement, with revisedpricing terms as mandated by the CPUC. The revised pricing terms are lower than the prices in the expiringpower sales agreement. Furthermore, earnings for the Watson and Sycamore projects are expected to decreasein 2009 from 2008, due primarily to lower projected energy prices and volumes. Additionally, projected steampurchased from the hosts for the Sycamore and Midway-Sunset projects are expected to be lower in 2009. Asa result of these factors, pre-tax earnings from the Big 4 projects are expected to decrease by approximately$45 million to $55 million during 2009.

Sunrise

Earnings from the Sunrise project decreased $9 million in 2008 from 2007 and $1 million in 2007 from 2006.The 2008 decrease was primarily due to lower availability incentive payments in 2008 and higher maintenanceexpenses due to unplanned outages in 2008. The 2007 decrease was primarily due to lower availabilityincentive payments partially offset by lower interest expense in 2007.

Seasonal Disclosure

EME’s third quarter equity in income from its energy projects is materially higher than equity in incomerelated to other quarters of the year due to warmer weather during the summer months and because a numberof EME’s energy projects located on the West Coast have power sales contracts that provide for higherpayments during the summer months.

Doga

Earnings from the Doga project decreased $6 million in 2008 compared to 2007 and increased $14 million in2007 compared to 2006. Effective March 31, 2007, EME accounted for its ownership in the Doga project onthe cost method (earnings are recognized when cash is distributed from the project). Earnings from Doga werehigher in 2007 when EME’s investment was fully recovered and earnings were recognized based ondistributions received from the Doga project. Earnings from Doga during 2006 were adversely impacted by achange in Turkish corporate tax rates which reduced deferred tax assets (related to levelization of income fromthe power purchase agreement for financial reporting purposes).

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Other Non-Wind Projects

Other non-wind projects increased $8 million in 2007 from 2006. The 2007 increase was primarily attributableto the improvement in the performance of EME’s gas transportation agreement resulting from increased gassupply in the Rocky Mountain region which increased the market price of gas transportation into California.

Other

Other decreased $24 million in 2008 from 2007 and $18 million in 2007 from 2006. The 2008 decreaseprimarily resulted from a charge of $23 million related to the termination of a turbine supply agreement inconnection with the Walnut Creek project. The 2007 decrease is partially attributable to a write-down ofcapitalized costs related to U.S. Wind Force. These amounts are reflected in “Gain on buyout of contract, losson termination of contract, asset write-down and other charges and credits” on EME’s consolidated statementsof income. In addition, in 2006, EME recorded an $8 million gain related to receipt of shares from MirantCorporation from a settlement of a claim recorded during the first quarter of 2006 reflected in other income(expense), net on EME’s consolidated statements of income.

EME Administrative and General Expenses

EME corporate administrative and general expenses increased $3 million in 2008 from 2007 and $61 millionin 2007 from 2006. The 2007 increase was primarily due to higher development costs incurred in 2007(mostly related to wind projects), higher corporate expenses and a loss accrual related to legal proceedingsrecorded in the third quarter of 2007.

Interest Income

Interest income decreased $62 million in 2008 from 2007. The 2008 decrease was primarily attributable tolower interest rates in 2008 compared to 2007 and lower average cash equivalents and short-term investmentbalances. The 2007 decrease was primarily attributable to lower average cash balances in 2007 compared to2006.

Interest Expense – Net of Amount Capitalized

Interest expense to third parties, before capitalized interest, decreased $34 million in 2008 from 2007 and$80 million in 2007 from 2006, respectively, primarily attributable to MEHC’s redemption in full of its seniorsecured notes in June 2007 and EME’s refinancing activities in May 2007. Capitalized interest increased$8 million in 2008 compared to 2007 and $16 million in 2007 compared to 2006. The increases wereprimarily due to wind projects under construction.

Loss on Early Extinguishment of Debt

Loss on early extinguishment of debt was $241 million in 2007 related to the early repayment of EME’s7.73% senior notes due June 15, 2009 and Midwest Generation’s 8.75% second priority senior secured notesdue May 1, 2034 and MEHC’s 13.5% senior secured notes due July 15, 2008.

Loss on early extinguishment of debt was $146 million in 2006 related to the early repayment of all EME’s10% senior notes due August 15, 2008 and 9.875% senior notes due April 15, 2011.

Income Taxes

Income tax provision from continuing operations was $243 million in 2008, $173 million in 2007 and$145 million in 2006. Income tax benefits are recognized pursuant to a tax-allocation agreement with EdisonInternational. See “EMG: Liquidity — Intercompany Tax-Allocation Agreement.” EME recognized$44 million, $29 million and $16 million of production tax credits related to wind projects for the years ended

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December 31, 2008, 2007 and 2006, respectively, and $5 million, $10 million and $14 million for each periodrelated to estimated state income tax benefits allocated from Edison International.

Results of Discontinued Operations

Income (loss) from discontinued operations, net of tax, at EME was $1 million in 2008, $(2) million in 2007and $98 million in 2006. The 2008 increase was due to adjustments for foreign exchange gains partially offsetby interest expense associated with contract indemnities related to EME’s sale of international projects inDecember 2004.

The 2007 decrease was largely attributable to distributions received from the Lakeland project (see“Discontinued Operations” for further discussion).

Related Party Transactions

Specified EME subsidiaries have ownership in partnerships that sell electricity generated by their projectfacilities to SCE and others under the terms of long-term power purchase agreements. Sales by thesepartnerships to SCE under these agreements amounted to $686 million, $747 million and $756 million in2008, 2007 and 2006, respectively.

Financial Services and Other Net Income

The following table sets forth the major changes in financial services net income:

In millions 2008 2007 2006

Financial services and other operating revenue $ 54 $ 56 $ 70

Other operation and maintenance 10 13 15Depreciation, decommissioning and amortization 4 9 13Contract buyout/termination and other (49) 2 —

Total operating expenses (35) 24 28

Operating Income 89 32 42Interest and dividend income 12 16 20Equity in income from partnerships and unconsolidated subsidiaries – net (3) 28 29Other nonoperating income — 2 22Interest expense – net of amounts capitalized (9) (10) (16)

Income from continuing operations before tax and minority interest 89 68 97

Income tax expense 29 (2) 9


Income (loss) from discontinued operations – net of tax — — —



Net income $ 60 $ 70 $ 88

Contract Buyout / Termination and Other

In March 2008, First Energy exercised an early buyout right under the terms of an existing lease agreementwith Edison Capital related to Unit No. 2 of the Beaver Valley Nuclear Power Plant. The termination date ofthe lease under the early buyout option was June 1, 2008. Proceeds from the sale were $72 million. EdisonCapital recorded a pre-tax gain of $41 million ($23 million after tax) during the second quarter of 2008. The2008 increase also reflects approximately $7 million in gains on the sale of investments at Edison Capital.

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Equity in Income from Partnerships and Unconsolidated Subsidiaries – Net

Equity in income from partnerships and unconsolidated subsidiaries – net decreased in 2008 mainly due togains from Edison Capital’s global infrastructure funds recorded in 2007.

Other Nonoperating Income

In 2006, Edison Capital recorded a $19 million pre-tax gain on the sale of certain investments, includingEdison Capital’s interest in an affordable housing project.

Income Tax Expense

The composite federal and state statutory income tax rate was approximately 40% (net of federal benefit ofstate income taxes) for all periods presented. The lower effective tax rates of 32.6%, (2.9)%, and 9.3%realized in 2008, 2007 and 2006 respectively, as compared to the statutory rate, were primarily due to low-income housing tax credits.

Historical Cash Flow Analysis

The “Historical Cash Flow Analysis” section of this MD&A discusses consolidated cash flows from operating,financing and investing activities.

Cash Flows from Operating Activities

Net cash provided by operating activities is as follows:


Continuing operations $ 2,210 $ 3,195 $ 3,474Discontinued operations — (2) 94

$ 2,210 $ 3,193 $ 3,568

Cash provided by operating activities from continuing operations decreased $985 million in 2008, compared to2007. The 2008 change was mainly due to a net $300 million increase in balancing account undercollections,mainly related to a $750 million increase in ERRA undercollections, partially offset by $200 million in refundpayments received related to SCE’s public purpose programs, $100 million refunded to ratepayers as a resultof SCE’s PBR decision, and a net $150 million in other balancing account overcollections. The change wasalso due to a $240 million decrease related to the elimination of amounts collected in 2008 for the repaymentof SCE rate reduction bonds. These bonds were fully repaid in December 2007. The bond payment is reflectedin financing activities. The decrease was partially offset by margin deposits received from counterparties atDecember 31, 2008. The 2008 change was also due to the timing of cash receipts and disbursements related toworking capital items.

Cash provided by operating activities from continuing operations decreased $279 million in 2007 compared to2006. The 2007 change reflects an increase of $48 million in required margin and collateral deposits in 2007for EMG’s hedging and trading activities, compared to a decrease of $625 million in 2006. This changeresulted from an increase in forward market prices in 2007 compared to 2006. The 2007 change also reflects adecrease in revenue collected from SCE’s customers primarily due to lower rates in 2007 compared to 2006.On February 14, 2007, SCE reduced its system average rate mainly as the result of estimated lower naturalgas prices in 2007, the refund of overcollections in the ERRA balancing account that occurred in 2006 and theimpact of the redesign of SCE’s tiered rate structure in 2007. The 2007 change was also due to the timing ofcash receipts and disbursements related to working capital items including lower income taxes paid in 2007compared to 2006.

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Cash provided by operating activities from discontinued operations decreased in 2007 from 2006 reflectinghigher distributions received in 2006 compared to 2007 from the Lakeland power project. See “DiscontinuedOperations” for more information regarding these distributions.

Cash Flows from Financing Activities

Net cash provided (used) by financing activities is as follows:


Continuing operations $ 3,210 $ (877) $ (703)

Cash provided (used) by financing activities from continuing operations mainly consisted of long-term debtissuances (payments) at SCE and EMG and dividends paid by Edison International to its commonshareholders.

Financing activities in 2008 were as follows:

• In January, SCE issued $600 million of first refunding mortgage bonds due in 2038. The proceeds wereused to repay SCE’s outstanding commercial paper of approximately $426 million and for generalcorporate purposes.

• During the first quarter, SCE purchased $212 million of its auction rate bonds, converted the issue to avariable rate structure, and terminated the FGIC insurance policy. SCE continues to hold the bonds whichremain outstanding and have not been retired or cancelled.

• In January, SCE repurchased 350,000 shares of 4.08% cumulative preferred stock at a price of $19.50 pershare. SCE retired this preferred stock in January 2008 and recorded a $2 million gain on the cancellationof reacquired capital stock (reflected in the caption “Common stock” on the consolidated balance sheets).

• In August, SCE issued $400 million of 5.50% first and refunding mortgage bonds due in 2018. Theproceeds were used to repay SCE’s outstanding commercial paper of approximately $110 million andborrowings under the credit facility of $200 million, as well as for general corporate purposes.

• In October, SCE issued $500 million of 5.75% first and refunding mortgage bonds due in 2014. Theproceeds were used for general corporate purposes.

• During 2008, SCE’s net issuances of short-term debt were $1.4 billion.

• During 2008, EME borrowed $851 million under its credit agreements.

• During 2008, Edison International’s (parent) net issuances of short-term debt were $250 million.

• Other financing activities in 2008 include dividend payments of $397 million paid by Edison Internationalto its common shareholders and payments of $66 million for the purchase and delivery of outstandingcommon stock for settlement of stock based awards (facilitated by a third party).

Financing activities in 2007 were as follows:

• In May 2007, EME issued $2.7 billion of senior notes, the proceeds of which were mostly used to repay$587 million of EME’s outstanding senior notes, repay $1 billion of Midwest Generation’s second prioritysenior secured notes, fund a dividend to MEHC which purchased approximately $796 million of its13.5% senior secured notes, and repay $328 million of Midwest Generation’s senior secured term loanfacility. In addition, EME and MEHC paid tender premiums and financing costs of $239 million related tothe debt refinancing.

• During 2007, SCE’s net issuance of short-term debt was $500 million.

• During the fourth quarter of 2007, SCE repaid the remaining outstanding balance of its rate reductionbonds in the amount of $246 million.

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Financing activities in 2006 included activities related to the rebalancing of SCE’s capital structure and ratebase growth and the reduction of debt at EMG, as follows:

• In January 2006, SCE issued $500 million of first and refunding mortgage bonds which consisted of$350 million of 5.625% bonds due in 2036 and $150 million of floating rate bonds due in 2009. Theproceeds from this issuance were used in part to redeem $150 million of variable rate first and refundingmortgage bonds due in January 2006 and $200 million of its 6.375% first and refunding mortgage bondsdue in January 2006.

• In January 2006, SCE issued 2,000,000 shares of 6% Series C preference stock (noncumulative,$100 liquidation value) and received net proceeds of approximately $197 million.

• In April 2006, SCE issued $331 million of tax-exempt bonds which consisted of $196 million of 4.10%bonds which are subject to remarketing in April 2013 and $135 million of 4.25% bonds which are subjectto remarketing in November 2016. The proceeds from this issuance were used to call and redeem$196 million of tax-exempt bonds due February 2008 and $135 million of tax-exempt bonds due March2008. This transaction was treated as a noncash financing activity.

• In June 2006, EME issued $1 billion of senior notes. The proceeds from this issuance were mostly used torepay $1 billion of EME’s outstanding senior notes and to pay $139 million for tender premiums andrelated fees.

• In December 2006, SCE issued $400 million of 5.55% first and refunding mortgage bonds due in 2037.The proceeds from this issuance were used for general corporate purposes.

• During 2006, Midwest Generation had net repayments of $170 million under its credit facility.


Cash Flows from Investing Activities

Net cash used by investing activities is as follows:


Continuing operations $ (2,945) $ (2,670) $ (2,963)

Cash flows from investing activities are affected by capital expenditures, SCE’s funding of nucleardecommissioning trusts, and proceeds and maturities of investments.

Investing activities in 2008 reflect $2.3 billion in capital expenditures at SCE, primarily for transmission anddistribution assets, including approximately $99 million for nuclear fuel acquisitions, and $556 million incapital expenditures at EMG primarily due to expansion of investments for renewable energy projects.Investing activities include investments in other assets at EMG of $213 million, related to turbine deposits forwind projects prior to commencement of construction. Investing activities also include net maturities and salesof short-term investments of $74 million and net purchases of nuclear decommissioning trust investments andother of $7 million, and proceeds of $28 million from the sale of 33% of EME’s membership in the ElkhornRidge wind project during the second quarter of 2008.

Investing activities in 2007 reflect $2.3 billion in capital expenditures at SCE, primarily for transmission anddistribution assets, including approximately $123 million for nuclear fuel acquisitions, and $540 million incapital expenditures at EMG. Investing activities include investments in other assets at EMG of $271 million

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related to turbine deposits for wind projects prior to commencement of construction. Investing activities alsoinclude net maturities and sales of short term investments of $477 million, net purchases of nucleardecommissioning trust investments and other of $133 million, payments of $22 million towards the purchaseprice of new wind projects, payment of $24 million during 2007 to acquire a 1% interest in twelve designatedprojects and the option to purchase the remaining 99% interest, and $11 million in payments made toward thepurchase price of EMG’s Wildorado wind project during the second quarter of 2007.

Investing activities in 2006 reflect $2.2 billion in capital expenditures at SCE, primarily for transmission anddistribution assets, including approximately $81 million for nuclear fuel acquisitions and $13 million related tothe Mountainview plant, and $310 million in capital expenditures at EMG. Investing activities includeinvestments in other assets at EMG, of $130 million related to turbine deposits for wind projects prior tocommencement of construction. Investing activities also include net purchases of marketable securities of$375 million at EMG, net purchases of nuclear decommissioning trust investments and other of $140 million,as well as the receipt of $43 million in proceeds from the sale of 25% of EME’s ownership interest in theSan Juan Mesa wind project. EMG also paid $18 million towards the purchase price of the Wildorado windproject during the first quarter of 2006.

DISCONTINUED OPERATIONS

EME previously owned a 220 MW power plant located in the United Kingdom, referred to as the Lakelandproject. An administrative receiver was appointed in 2002 as a result of a default by the project’s counterparty,a subsidiary of TXU Europe Group plc. Following a claim for termination of the power sales agreement, theLakeland project received a settlement of £116 million (approximately $217 million) in 2005. EME wasentitled to receive the remaining amount of the settlement after payment of creditor claims. As creditor claimswere settled, EME received payments of £0.4 million (approximately $1 million) in 2008, £5 million(approximately $10 million) in 2007, and £72 million (approximately $125 million) in 2006. The after-taxincome attributable to the Lakeland project was $1 million, $6 million and $85 million for 2008, 2007 and2006, respectively. Beginning in 2002, EME reported the Lakeland project as discontinued operations andaccounted for its ownership of Lakeland Power on the cost method (earnings are recognized as cash isdistributed from the project).

For all years presented, the results of EME’s international projects, discussed above, have been accounted foras discontinued operations on the consolidated financial statements in accordance with SFAS No. 144.

There was no revenue from discontinued operations in 2008, 2007 or 2006. The pre-tax earnings fromdiscontinued operations were $6 million in 2008, $3 million in 2007 and $118 million in 2006.

During the fourth quarter of 2006, EME recorded a tax benefit adjustment of $22 million, which resulted fromresolution of a tax uncertainty pertaining to the ownership interest in a foreign project. EME’s payment of$34 million during the second quarter of 2006 related to an indemnity to IPM for matters arising out of theexercise by one of its project partners of a right of first refusal resulted in a $3 million additional lossrecorded in 2006.

There were no assets or liabilities of discontinued operations at December 31, 2008 and 2007.

ACQUISITIONS AND DISPOSITIONS

Acquisitions

On January 5, 2006, EME completed a transaction with Cielo Wildorado, G.P., LLC and Cielo Capital, L.P. toacquire a 99.9% interest in Wildorado Wind, L.P., which owns a 161 MW wind farm located in the panhandleof northern Texas, referred to as the Wildorado wind project. The acquisition included all development rights,title and interest held by Cielo in the Wildorado wind project, except for a small minority stake in the projectretained by Cielo. The total purchase price was $29 million. This project started construction in April 2006and commenced commercial operation during April 2007. The acquisition was accounted for utilizing the

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purchase method. The fair value of the Wildorado wind project was equal to the purchase price and as aresult, the total purchase price was allocated to property, plant and equipment on Edison International’sconsolidated balance sheet.

Dispositions

On March 7, 2006, EME completed the sale of a 25% ownership interest in the San Juan Mesa wind projectto Citi Renewable Investments I LLC, a wholly owned subsidiary of Citicorp North America, Inc. Proceedsfrom the sale were $43 million. EME recorded a pre-tax gain on the sale of approximately $4 million duringthe first quarter of 2006.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

The accounting policies described below are viewed by management as critical because their application is themost relevant and material to Edison International’s results of operations and financial position and thesepolicies require the use of material judgments and estimates.

Rate Regulated Enterprises

SCE applies SFAS No. 71 to the portion of its operations in which regulators set rates at levels intended torecover the estimated costs of providing service, plus a return on its net investment, or rate base. Regulatorsalso may impose certain penalties or grant certain incentives. Due to timing and other differences in thecollection of revenue, these principles allow an incurred cost that would otherwise be charged to expense by anonregulated entity to be capitalized as a regulatory asset if it is probable that the cost is recoverable throughfuture rates; conversely the principles allow creation of a regulatory liability for probable future costs collectedthrough rates in advance. SCE’s management continually assesses whether the regulatory assets are probableof future recovery by considering factors such as the current regulatory environment, the issuance of rateorders on recovery of the specific incurred cost or a similar incurred cost to SCE or other rate-regulatedentities in California, and assurances from the regulator (as well as its primary intervenor groups) that theincurred cost will be treated as an allowable cost for rate-making purposes. Because current rates include therecovery of existing regulatory assets and settlement of regulatory liabilities, and rates in effect are expected toallow SCE to earn a reasonable rate of return, management believes that existing regulatory assets andliabilities are probable of recovery. This determination reflects the current political and regulatory climate inCalifornia and is subject to change in the future. If future recovery of costs ceases to be probable, all or partof the regulatory assets and liabilities would have to be written off against current period earnings. AtDecember 31, 2008, the consolidated balance sheets included regulatory assets of $6.0 billion and regulatoryliabilities of $3.6 billion. Management continually evaluates the anticipated recovery of regulatory assets,incentives and revenue subject to refund, as well as the anticipated cost of regulatory liabilities or penaltiesand provides for allowances and/or reserves as appropriate.

Derivative Financial Instruments and Hedging Activities

Edison International follows SFAS No. 133 which requires derivative financial instruments to be recorded attheir fair value unless an exception applies. SFAS No. 133 also requires that changes in a derivative’s fairvalue be recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives thatqualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset bychanges in the fair value of the hedged assets, liabilities or firm commitments through earnings, or recognizedin other comprehensive income until the hedged item is recognized in earnings. The remaining gain or loss onthe derivative instrument, if any, is recognized currently in earnings. SCE fair value changes are expected tobe recovered from or refunded to ratepayers, and therefore SCE’s fair value changes have no impact onearnings, but may temporarily affect cash flows.

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Derivative assets and liabilities are shown at gross amounts on the consolidated balance sheets, except that netpresentation is used when Edison International has the legal right of offset, such as multiple contracts executedwith the same counterparty under master netting arrangements. The results of derivative activities are recordedas part of cash flows from operating activities in the consolidated statements of cash flows. Management’sjudgment is required to determine if a transaction meets the definition of a derivative and, if it does, whetherthe normal sales and purchases exception applies or whether individual transactions qualify for hedgeaccounting treatment.

Determining whether or not Edison International’s transactions meet the definition of a derivative instrumentrequires management to exercise significant judgment, including determining whether the transaction has oneor more underlyings, one or more notional amounts, requires no initial net investment, and whether the termsrequire or permit net settlement. If it is determined that the transaction meets the definition of a derivativeinstrument, additional management judgment is exercised in determining whether the normal sales andpurchases exception applies or whether individual transactions qualify for hedge accounting treatment, ifelected.

Most of SCE’s QF contracts are not required to be recorded on its balance sheet because they either do notmeet the definition of a derivative or meet the normal purchases and sales exception. However, SCE purchasespower from certain QFs in which the contract pricing is based on a natural gas index, but the power is notgenerated with natural gas. The portion of these contracts that is not eligible for the normal purchases andsales exception under accounting rules is recorded on the balance sheet at fair value, based on financialmodels. Unit-specific contracts (signed or modified after June 30, 2003) in which SCE takes virtually all ofthe output of a facility are generally considered to be leases under EITF No. 01-8.

EME uses derivative financial instruments for hedging activities and trading purposes. Derivative financialinstruments are mainly utilized by EME to manage exposure from changes in electricity and fuel prices, andinterest rates. The majority of EME’s long-term power sales and fuel supply agreements related to itsgeneration activities either: (1) do not meet the definition of a derivative, or (2) qualify as normal purchasesand sales and are, therefore, recorded on an accrual basis.

Derivative financial instruments used for trading purposes include forwards, futures, options, swaps and otherfinancial instruments with third parties. EME records derivative financial instruments used for trading at fairvalue. The majority of EME’s derivative financial instruments with a short-term duration (less than one year)are valued using quoted market prices. In the absence of quoted market prices, derivative financial instrumentsare valued considering the time value of money, volatility of the underlying commodity, and other factors asdetermined by EME. Resulting gains and losses are recognized in nonutility power generation revenue in theaccompanying consolidated statements of income in the period of change. Derivative assets include openfinancial positions related to derivative financial instruments recorded at fair value, including cash flowhedges, that are “in-the-money” and the present value of net amounts receivable from structured transactions.Derivative liabilities include open financial positions related to derivative financial instruments, including cashflow hedges that are “out-of-the-money.”

For those transactions that are accounted for as derivative instruments, determining the fair value requiresmanagement to exercise significant judgment. Edison International makes estimates and assumptionsconcerning future commodity prices, load requirements and interest rates in determining the fair value of aderivative instrument. The fair value of a derivative is susceptible to significant change resulting from anumber of factors, including volatility of commodity prices, credit risks, market liquidity and discount rates.See “SCE: Market Risk Exposures” and “EMG: Market Risk Exposures” for a description of risk managementactivities and sensitivities to change in market prices.

Fair Value Accounting

Edison International follows SFAS No. 157 which established a framework for measuring fair value.SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a

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liability in an orderly transaction between market participants as of the measurement date (referred to as an“exit price” in SFAS No. 157). Edison International’s assets and liabilities carried at fair value primarilyconsist of derivative contracts, nuclear decommissioning trust investments, pension and postretirement benefitsother than pension, and money market funds. Derivative contracts primarily relate to power and gas andinclude contracts for forward physical sales and purchases, options and forward price swaps which settle onlyon a financial basis (including futures contracts). Derivative contracts can be exchange traded, over-the-countertraded, or structured transactions.

Edison International makes estimates and significant judgments in order to determine the fair value of aninstrument including those related to quoted market prices, time value of money, volatility of the underlyingcommodities, non-performance risks of counterparties and other factors. If quoted market prices are notavailable, SCE uses internally maintained standardized or industry accepted models to determine the fairvalue. The models are updated with spot prices, forward prices, volatilities and interest rates from regularlypublished and widely distributed independent sources. Under SFAS No. 157, when actual market prices, orrelevant observable inputs are not available, it is appropriate to use unobservable inputs which reflectmanagement assumptions, including extrapolating limited short-term observable data and developingcorrelations between liquid and non-liquid trading hubs. In assessing non-performance risks, EME reviewscredit ratings of counterparties (and related default rates based on such credit ratings) and prices of creditdefault swaps. The market price (or premium) for credit default swaps represents the price that a counterpartywould pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is notdirectly comparable to the credit risks of derivative contracts, but provides market information of the relatedrisk of non-performance.

In addition, SFAS No. 157 established a fair value hierarchy that prioritizes the inputs to valuation techniquesused to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices inactive markets for identical assets and liabilities (Level 1 measurements) and the lowest priority tounobservable inputs (Level 3 measurements) (see “Edison International Notes to Consolidated FinancialStatements — Note 10. Fair Value Measurements” for further information).

Level 3 includes the majority of SCE’s derivatives, including over-the-counter options, bilateral contracts,capacity contracts, and QF contracts. The fair value of these SCE derivatives is determined usinguncorroborated non-binding broker quotes (from one or more brokers) and models which may require SCE toextrapolate short-term observable inputs in order to calculate fair value. Broker quotes are obtained fromseveral brokers and compared against each other for reasonableness. SCE has Level 3 fixed float swaps forwhich SCE obtains the applicable Henry Hub and basis forward market prices from the New York MercantileExchange. However, these swaps have contract terms that extend beyond observable market data and theunobservable inputs incorporated in the fair value determination are considered significant compared to theoverall swap’s fair value.

Level 3 also includes derivatives that trade infrequently (such as financial transmission rights, FTRs and CRRsin the California market and over-the-counter derivatives at illiquid locations), derivatives with counterpartiesthat have significant non-performance risks and long-term power agreements. For illiquid financialtransmission rights, FTRs and CRRs, Edison International reviews objective criteria related to systemcongestion and other underlying drivers and adjusts fair value when Edison International concludes a changein objective criteria would result in a new valuation that better reflects the fair value. Recent auction prices areused to determine the fair value of short-term CRRs. Edison International recorded liquidity reserves againstthe long-term CRRs fair values since there were no quoted long-term market prices for the CRRs andinsufficient evidence of long-term market prices.

Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term poweragreements, fair value is based upon a discounting of future electricity and natural gas prices derived from aproprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk andmarket liquidity. Changes in fair value are based on changes to forward market prices, including forecasted

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prices for illiquid forward periods. In circumstances where Edison International cannot verify fair value withobservable market transactions, it is possible that a different valuation model could produce a materiallydifferent estimate of fair value. As markets continue to develop and more pricing information becomesavailable, Edison International continues to assess valuation methodologies used to determine fair value.

The amount of Edison International’s Level 3 derivative assets and liabilities measured using significantunobservable inputs as a percentage of the total derivative assets and total derivative liabilities (excludingnetting and collateral) measured at fair value were 51% and 65%, respectively.

SCE’s investment policies and CPUC requirements place limitations on the types and investment grade ratingsof the securities that may be held by the nuclear decommissioning trust funds. These policies restrict the trustfunds from holding alternative investments and limit the trust funds’ exposures to investments in highlyilliquid markets. With respect to equity securities, the trustee obtains prices from pricing services, whoseprices are obtained from direct feeds from market exchanges, which SCE is able to independently corroborate.Regarding fixed income securities, the trustee receives multiple prices from pricing services, which enablecross-provider validations by the trustee in addition to unusual daily movement checks. A primary price sourceis identified based on asset type, class or issue for each security. The trustee monitors prices supplied bypricing services and may use a supplemental price source or change the primary price source of a givensecurity if the trustee challenges an assigned price and determines that another price source is considered to bepreferable. Additionally, SCE corroborates the fair values of securities by comparison to other market-basedprice sources obtained by SCE’s investment managers. The trustee validation procedures for pension andPBOP assets are the same as the nuclear decommissioning trusts. Level 3 includes prices or valuations thatrequire inputs that are both significant to the fair value measurements and unobservable.

Management uses significant judgment and assumptions in order to determine the fair value of Level 3transactions. Due to its regulatory treatment, SCE’s fair value transactions discussed above are recovered inrates. EME’s fair value transactions discussed above could have a material impact on financial results.

Income Taxes

Edison International’s eligible subsidiaries are included in Edison International’s consolidated federal incometax and combined state tax returns. Edison International has tax-allocation and payment agreements withcertain of its subsidiaries. For subsidiaries other than SCE, the right of a participating subsidiary to receive ormake a payment and the amount and timing of tax-allocation payments are dependent on the inclusion of thesubsidiary in the consolidated income tax returns of Edison International and other factors including theconsolidated taxable income of Edison International and its includible subsidiaries, the amount of taxableincome or net operating losses and other tax items of the participating subsidiary, as well as the othersubsidiaries of Edison International. There are specific procedures regarding allocations of state taxes. Eachsubsidiary is eligible to receive tax-allocation payments for its tax losses or credits only at such time as EdisonInternational and its subsidiaries generate sufficient taxable income to be able to utilize the participatingsubsidiary’s losses in the consolidated income tax return of Edison International. Under an income tax-allocation agreement approved by the CPUC, SCE’s tax liability is computed as if it filed its federal and stateincome tax returns on a separate return basis.

Edison International applies the asset and liability method of accounting for deferred income taxes as requiredby SFAS No. 109, “Accounting for Income Taxes.” In accordance with FIN 48, “Accounting for Uncertainty inIncome Taxes,” Edison International applies judgment to assess each tax position taken on filed tax returnsand tax positions expected to be taken on future returns to determine whether a tax position is more likelythan not to be sustained and recognized in the financial statements. However, all temporary tax positions,whether or not the more likely than not threshold of FIN 48 is met, are recorded in the financial statements inaccordance with the measurement principles of FIN 48.

As part of the process of preparing its consolidated financial statements, Edison International is required toestimate its income taxes in each jurisdiction in which it operates. This process involves estimating actual

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current tax expense together with assessing temporary differences resulting from differing treatment of items,such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets andliabilities, which are included within Edison International’s consolidated balance sheet. Edison Internationaltakes certain tax positions it believes are applied in accordance with tax laws. The application of thesepositions is subject to interpretation and audit by the IRS. As further described in “Other Developments —Federal and State Income Taxes,” the IRS has raised issues in the audit of Edison International’s tax returnswith respect to certain leveraged leases of Edison Capital.

Investment tax credits associated with rate-regulated public utility property are deferred and amortized overthe lives of the properties and production tax credits are recognized in the period in which they are earned.

Accounting for tax obligations requires judgments, including estimating reserves for potential adverseoutcomes regarding tax positions that have been taken. Management uses judgment in determining whether theevidence indicates it is more likely than not, based solely on the technical merits, that the position will besustained on audit. Management continually evaluates its income tax exposures and provides for allowancesand/or reserves as appropriate, reflected in the captions “Accrued taxes” and “Other deferred credits and long-term liabilities” on the consolidated balance sheets. Income tax expense includes the current tax liability fromoperations and the change in deferred income taxes during the year. Interest expense and penalties associatedwith income taxes are reflected in the caption “Income tax expense” on the consolidated statements of income.

Off-Balance Sheet Financing

EME has entered into sale-leaseback transactions related to the Powerton and Joliet plants in Illinois and theHomer City facilities in Pennsylvania (See “Off-Balance Sheet Transactions”). Each of these transactions wascompleted and accounted for in accordance with SFAS No. 98, which requires, among other things, that all therisk and rewards of ownership of assets be transferred to a new owner without continuing involvement in theassets by the former owner other than as normal for a lessee. The sale-leaseback transactions of these powerplants were complex matters that involved management judgment to determine compliance with SFAS No. 98,including the transfer of all the risk and rewards of ownership of the power plants to the new owner withoutEME’s continuing involvement other than as normal for a lessee. These transactions were entered into toprovide a source of capital either to fund the original acquisition of the assets or to repay indebtednesspreviously incurred for the acquisition. Each of these leases uses special purpose entities.

Based on existing accounting guidance, EME does not record these lease obligations in its consolidatedbalance sheets. If these transactions were required to be consolidated as a result of future changes inaccounting guidance, it would: (1) increase property, plant and equipment and long-term obligations in theconsolidated financial position, and (2) impact the pattern of expense recognition related to these obligationsbecause EME would likely change from its current straight-line recognition of rental expense to recognition ofstraight-line depreciation on the leased assets as well as the interest component of the financings which isweighted more heavily toward the early years of the obligations. The difference in expense recognition wouldnot affect EME’s cash flows under these transactions. See “Off-Balance Sheet Transactions.”

Edison Capital has entered into lease transactions, as lessor, related to various power generation, electrictransmission and distribution, transportation and telecommunications assets. All of the debt under EdisonCapital’s leveraged leases is nonrecourse and is not recorded on Edison International’s balance sheets inaccordance with SFAS No. 13, “Accounting for Leases.”

Partnership investments, in which Edison International owns a percentage interest and does not haveoperational control or significant voting rights, are accounted for under the equity method as required byAccounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in CommonStock.” As such, the project assets and liabilities are not consolidated on the balance sheets. Rather, thefinancial statements reflect only the proportionate ownership share of net income or loss. See “Off-BalanceSheet Transactions.”

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Asset Impairment

Edison International evaluates the impairment of its investments in projects and other long-lived assets basedon a review of estimated cash flows expected to be generated whenever events or changes in circumstancesindicate the carrying amount of such investments or assets may not be recoverable. If the carrying amount ofthe investment or asset exceeds the amount of the expected future cash flows, undiscounted and withoutinterest charges, then an impairment loss for investments in projects and other long-lived assets is recognizedin accordance with Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting forInvestments in Common Stock” and SFAS No. 144, respectively. In accordance with SFAS No. 71, SCE’simpaired assets are recorded as a regulatory asset if it is deemed probable that such amounts will be recoveredfrom the ratepayers.

The assessment of impairment is a critical accounting estimate because significant management judgment isrequired to determine: (1) if an indicator of impairment has occurred, (2) how assets should be grouped,(3) the forecast of undiscounted expected future cash flow over the asset’s estimated useful life to determine ifan impairment exists, and (4) if an impairment exists, the fair value of the asset or asset group. Factors thatEdison International considers important, which could trigger an impairment, include operating losses from aproject, projected future operating losses, the financial condition of counterparties, or significant negativeindustry or economic trends. The expected future undiscounted cash flow from EME’s assets or group ofassets is a critical accounting policy because: (1) estimates of future prices of energy and capacity inwholesale energy markets and fuel prices are susceptible to significant change, (2) uncertainties existregarding the impact of existing and future environmental regulations, (3) the period of the forecast is over anextended period of time due to the length of the estimated remaining useful lives, and (4) the impact of animpairment on EME’s consolidated financial position and results of operations would be material.

Midwest Generation has regulatory requirements in Illinois to reduce SO2 and NOx emissions to target ratesand to install specific environmental control equipment by specific dates for each coal unit (except Unit 6 atJoliet Station) or it would be required to shut down the specified coal unit. See “Other Developments —Environmental Matters” for further discussion regarding the CPS. No decision has been made to make suchcapital improvements. The decision to make capital improvements is dependent on a number of factorsaffecting the economic analysis and potential impact of further environmental regulations. If EME were todecide not to install additional environmental control equipment and, instead, shut down an entire plant by thedate required, the remaining estimated useful life of the plant would be shortened (thereby increasing theannual depreciation expense). The change in estimated useful life could trigger an impairment. If theundiscounted expected cash flow measured at a plant level were less than the net book value of the assetgroup, an impairment would be recognized. EME includes allocated acquired emission allowances as part ofthe asset group under SFAS No. 144. In the case of the Powerton and Joliet Stations, EME also includesprepaid rent in the asset group. EME’s unit of account is at the plant level and, accordingly, the closure of aunit at a multi-unit site would not result in an impairment of property, plant and equipment unless suchcondition were to affect an impairment assessment on the entire plant.

Nuclear Decommissioning

Edison International’s legal AROs related to the decommissioning of SCE’s nuclear power facilities arerecorded at fair value. The fair value of decommissioning SCE’s nuclear power facilities is based on site-specific studies performed in 2005 for SCE’s San Onofre and Palo Verde nuclear facilities. Changes in theestimated costs or timing of decommissioning, or the assumptions underlying these estimates are based onmanagement judgments and could cause material revisions to the estimated total cost to decommission thesefacilities. SCE estimates that it will spend approximately $11.5 billion through 2049 to decommission itsactive nuclear facilities. This estimate is based on SCE’s decommissioning cost methodology used for rate-making purposes, escalated at rates ranging from 1.7% to 7.5% (depending on the cost element) annually.

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Nuclear decommissioning costs are recovered in utility rates. These costs are expected to be funded fromindependent decommissioning trusts, which currently receive contributions of approximately $46 million peryear. As of December 31, 2008, the decommissioning trust balance was $2.5 billion. Contributions to thedecommissioning trusts are reviewed every three years by the CPUC. The next filing is in April 2009 forcontribution changes in 2011. The contributions are determined based on an analysis of the current value oftrust assets and long-term forecasts of cost escalation, the estimate and timing of decommissioning costs, andafter-tax return on trust investments. Favorable or unfavorable investment performance in a period will notchange the amount of contributions for that period. However, trust performance for the three years leading upto a CPUC review proceeding will provide input into future contributions. The CPUC has set certainrestrictions related to the investments of these trusts. If additional funds are needed for decommissioning, it isprobable that the additional funds will be recoverable through customer rates. Trust funds are recorded on thebalance sheet at fair market value.

SCE’s nuclear decommissioning trusts are accounted for in accordance with SFAS No. 115 and due toregulatory recovery of SCE’s nuclear decommissioning expense, rate-making accounting treatment is appliedto all nuclear decommissioning trust activities in accordance with SFAS No. 71. As a result, nucleardecommissioning activities do not affect SCE’s earnings.

SCE’s nuclear decommissioning trust investments are classified as available-for-sale. SCE has debt and equityinvestments for the nuclear decommissioning trust funds. Due to regulatory mechanisms, earnings and realizedgains and losses (including other-than-temporary impairments) have no impact on electric utility revenue.Unrealized gains and losses on decommissioning trust funds increase or decrease the trust assets and therelated regulatory asset or liability and have no impact on electric utility revenue or decommissioning expense.SCE reviews each security for other-than-temporary impairment losses on the last day of each monthcompared to the last day of the previous month. If the fair value on both days is less than the cost for thatsecurity, SCE will recognize a realized loss for the other-than-temporary impairment. If the fair value isgreater or less than the cost for that security at the time of sale, SCE will recognize a related realized gain orloss, respectively.

Decommissioning of San Onofre Unit 1 is underway. All of SCE’s San Onofre Unit 1 decommissioning costswill be paid from its nuclear decommissioning trust funds, subject to CPUC review. The estimated remainingcost to decommission San Onofre Unit 1 of $59 million as of December 31, 2008 is recorded as an AROliability.

Pensions and Postretirement Benefits Other than Pensions

SFAS No. 158 requires companies to recognize the overfunded or underfunded status of defined benefitpension and other postretirement plans as assets and liabilities in the balance sheet; the assets and/or liabilitiesare normally offset through other comprehensive income (loss). Edison International adopted SFAS No. 158 asof December 31, 2006. In accordance with SFAS No. 71, Edison International recorded regulatory assets andliabilities instead of charges and credits to other comprehensive income (loss) for its postretirement benefitplans that are recoverable in utility rates. SFAS No. 158 also requires companies to align the measurementdates for their plans to their fiscal year-ends. Edison International already has a fiscal year-end measurementdate for all of its postretirement plans.

Pension and other postretirement obligations and the related effects on results of operations are calculatedusing actuarial models. Two critical assumptions, discount rate and expected return on assets, are importantelements of plan expense and liability measurement. Additionally, health care cost trend rates are criticalassumptions for postretirement health care plans. These critical assumptions are evaluated at least annually.Other assumptions, which require management judgment, such as retirement, mortality and turnover, areevaluated periodically and updated to reflect actual experience.

The discount rate enables Edison International to state expected future cash flows at a present value on themeasurement date. Edison International selects its discount rate by performing a yield curve analysis. This

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analysis determines the equivalent discount rate on projected cash flows, matching the timing and amount ofexpected benefit payments. Two corporate yield curves were considered, Citigroup and AON. At theDecember 31, 2008 measurement date, Edison International used a discount rate of 6.25% for both pensionsand PBOPs.

To determine the expected long-term rate of return on pension plan assets, current and expected assetallocations are considered, as well as historical and expected returns on plan assets. The expected rate ofreturn on plan assets was 7.5% for pensions and 7.0% for PBOP. A portion of PBOP trusts asset returns aresubject to taxation, so the 7.0% rate of return on plan assets above is determined on an after-tax basis. Actualtime-weighted, annualized returns (losses) on the pension plan assets were (31.0)%, 1.5% and 4.1% for theone-year, five-year and ten-year periods ended December 31, 2008, respectively. Actual time-weighted,annualized returns (losses) on the PBOP plan assets were (31.1)%, (0.2)%, and 1.0% over these same periods.Accounting principles provide that differences between expected and actual returns are recognized over theaverage future service of employees.

SCE accounts for about 92% of Edison International’s total pension obligation, and 96% of its assets held intrusts, at December 31, 2008. SCE records pension expense equal to the amount funded to the trusts, ascalculated using an actuarial method required for rate-making purposes, in which the impact of marketvolatility on plan assets is recognized in earnings on a more gradual basis. Any difference between pensionexpense calculated in accordance with rate-making methods and pension expense calculated in accordancewith SFAS No. 87, “Employers’ Accounting for Pensions,” and SFAS No. 158 is accumulated as a regulatoryasset or liability, and will, over time, be recovered from or returned to customers. As of December 31, 2008,this cumulative difference amounted to a regulatory liability of $71 million, meaning that the rate-makingmethod has recognized $71 million more in expense than the accounting method since implementation ofSFAS No. 87 in 1987.

Edison International’s pension and PBOP plans are subject to limits established for federal tax deductibility.SCE funds its pension and PBOP plans in accordance with amounts allowed by the CPUC. Executive pensionplans and nonutility PBOP plans have no plan assets.

At December 31, 2008, Edison International’s PBOP plans had a $2.4 billion benefit obligation. Total expensefor these plans was $39 million for 2008. The health care cost trend rate is 9.25% for 2008, graduallydeclining to 5.0% for 2015 and beyond. Increasing the health care cost trend rate by one percentage pointwould increase the accumulated obligation as of December 31, 2008 by $263 million and annual aggregateservice and interest costs by $18 million. Decreasing the health care cost trend rate by one percentage pointwould decrease the accumulated obligation as of December 31, 2008 by $236 million and annual aggregateservice and interest costs by $16 million.

Accounting for Contingencies

In accordance with SFAS No. 5, “Accounting for Contingencies,” Edison International records losscontingencies when it determines that the outcome of future events is probable of occurring and when theamount of the loss can be reasonably estimated. These reserves are based on management judgment andestimates taking into consideration available information and are adjusted when events or circumstances causethese judgments or estimates to change. Edison International provides disclosure for contingencies when thereis a reasonable possibility that a loss or an additional loss may be incurred. Gain contingencies are recognizedin the financial statements when they are realized. Actual amounts realized upon settlement of contingenciesmay be different than amounts recorded and disclosed and could have a significant impact on the liabilities,revenue and expenses recorded in the financial statements. See “SCE: Regulatory Matters” and “OtherDevelopments” for a discussion of contingencies and regulatory issues.

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NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements are discussed in Note 1 — Summary of Significant Accounting Policies —New Accounting Pronouncements under “Edison International’s Notes to Consolidated Financial Statements.”

COMMITMENTS, GUARANTEES AND INDEMNITIES

Edison International’s commitments as of December 31, 2008, for the years 2009 through 2013 and thereafterare estimated below:

In millions 2009 2010 2011 2012 2013 Thereafter

Long-term debt maturities andinterest(1) $ 824 $ 930 $ 641 $ 1,479 $ 1,095 $ 15,368

Fuel supply contract payments 667 278 173 202 192 725Gas and coal transportation

payments 245 169 8 8 8 35Purchased-power capacity

payments 289 368 519 681 660 4,308Operating lease obligations 1,051 1,023 832 718 701 4,161Capital lease obligations 4 12 17 19 19 1,153Turbine commitments 706 232 — — — —Capital improvements 150 — — — — —Other commitments 67 85 74 63 33 24Employee benefit plans contributions(2) 179 — — — — —

Total(3) $ 4,182 $ 3,097 $ 2,264 $ 3,170 $ 2,708 $ 25,774

(1) Amount includes scheduled principal payments for debt outstanding as of December 31, 2008 and relatedforecast interest payments over the applicable period of the debt.

(2) Amount includes estimated contributions to the pension and PBOP plans. The estimated contributions forSCE and EME are not available beyond 2009.

(3) At December 31, 2008, Edison International had a total net liability recorded for uncertain tax positions of$450 million, which is excluded from the table. Edison International cannot make reliable estimates of thecash flows by period due to uncertainty surrounding the timing of resolving these open tax issues with theIRS.

Fuel Supply Contracts

SCE has fuel supply contracts which require payment only if the fuel is made available for purchase. SCE hasa coal fuel contract that requires payment of certain fixed charges whether or not coal is delivered.

At December 31, 2008, Midwest Generation and EME Homer City had fuel purchase commitments withvarious third-party suppliers. The minimum commitments are based on the contract provisions, which consistof fixed prices, subject to adjustment clauses. In connection with the acquisition of the Illinois Plants, MidwestGeneration had assumed a long-term coal supply contract and recorded a liability to reflect the fair value ofthis contract. In March 2008, Midwest Generation entered into an agreement to buy out its coal obligations forthe years 2009 through 2012 under this contract with a one-time payment to be made in January 2009.

Gas and Coal Transportation

At December 31, 2008, EME had a contractual commitment to transport natural gas. EME is committed topay its share of fixed monthly capacity charges under its gas transportation agreement, which has a remainingcontract length of nine years.

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At December 31, 2008, Midwest Generation had contractual commitments for the transport of coal to theirrespective facilities. Midwest Generation’s primary contract is with Union Pacific Railroad (and variousdelivering carriers) which extends through 2011. Midwest Generation commitments under this agreement arebased on actual coal purchases from the PRB. Accordingly, Midwest Generation’s contractual obligations fortransportation are based on coal volumes set forth in its fuel supply contracts.

Power-Purchase Contracts

SCE has power-purchase contracts with certain QFs (cogenerators and small power producers) and otherpower producers. These contracts provide for capacity payments if a facility meets certain performanceobligations and energy payments based on actual power supplied to SCE (the energy payments are notincluded in the table above). There are no requirements to make debt-service payments. In an effort to replacehigher-cost contract payments with lower-cost replacement power, SCE has entered into power-purchasesettlements to end its contract obligations with certain QFs. The settlements are reported as power-purchasecontracts on the consolidated balance sheets.

Operating and Capital Leases

In accordance with EITF No. 01-8, power contracts signed or modified after June 30, 2003, need to beassessed for lease accounting requirements. Unit specific contracts in which SCE takes virtually all of theoutput of a facility are generally considered to be leases. As of December 31, 2005, SCE had six powercontracts classified as operating leases. In 2006, SCE modified 62 power contracts. No contracts weremodified in 2007 and 2008. The modifications to the contracts resulted in a change to the contractual terms ofthe contracts at which time SCE reassessed these power contracts under EITF No. 01-8 and determined thatthe contracts are leases and subsequently met the requirements for operating leases under SFAS No. 13. Thesepower contracts had previously been grandfathered relative to EITF No. 01-8 and did not meet the normalpurchases and sales exception. As a result, these contracts were recorded on the consolidated balance sheets atfair value in accordance with SFAS No. 133. Due to regulatory mechanisms, fair value changes did not affectearnings. At the time of modification, SCE had assets and liabilities related to mark-to-market gains or losses.Under SFAS No. 133, the assets and liabilities were reclassified to a lease prepayment or accrual and wereincluded in the cost basis of the lease. The lease prepayment and accruals are being amortized over the life ofthe lease on a straight-line basis. At December 31, 2008, the net liability was $64 million. At December 31,2008, SCE had 69 power contracts classified as operating leases. Operating lease expense for power purchaseswas $328 million in 2008, $297 million in 2007, and $188 million in 2006. In addition, as of December 31,2008, SCE had four power purchase contracts which met the requirements for capital leases. These capitalleases have a net commitment of $1.22 billion at December 31, 2008 and $20 million at December 31, 2007.SCE’s total estimated capital lease executory costs and interest expense were $1.71 billion at December 31,2008 and $20 million at December 31, 2007.

At December 31, 2008, minimum operating lease payments were primarily related to long-term leases for thePowerton and Joliet Stations and the Homer City facilities. During 2000, EME entered into sale-leasebacktransactions for two power facilities, the Powerton and Units 7 and 8 of the Joliet coal-fired stations located inIllinois, with third-party lessors. During the fourth quarter of 2001, EME entered into a sale-leasebacktransaction for the Homer City coal-fired facilities located in Pennsylvania, with third-party lessors. Totalminimum lease payments during the next five years are $336 million in 2009, $325 million in 2010,$311 million in 2011, $311 million in 2012, $300 million in 2013, and the minimum lease payments due after2013 are $2.0 billion. For further discussion, see “— Off-Balance Sheet Transactions — Sale-LeasebackTransactions.”

Edison International has other operating leases for office space, vehicles, property and other equipment (withvarying terms, provisions and expiration dates).

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Turbine Commitments

EME had entered into various turbine supply agreements with vendors to support its wind development efforts.At December 31, 2008, EME had secured 484 wind turbines (942 MW) for use in future projects for anaggregate purchase price of $1.2 billion. One of EME’s turbine suppliers has requested an escalationadjustment to its pricing for 2008 and 2009 turbines pursuant to its turbine supply agreement. EME isevaluating the request, and discussions with the supplier are ongoing. Under certain of these agreements, EMEmay terminate the purchase of individual turbines, or groups of turbines, for convenience. Upon any suchtermination, EME may be obligated to pay termination charges to the vendor.

For a discussion on wind turbine performance issues, see “Results of Operations and Historical Cash FlowAnalysis — Nonutility Power Generation Net Income — Renewable Energy Projects” and “EMG: Market RiskExposures — Credit Risk.”

Capital Improvements

At December 31, 2008, EME’s subsidiaries had firm commitments in 2009 for capital and constructionexpenditures. The majority of these expenditures primarily relate to the construction of wind projects andenvironmental improvements at the Illinois Plants. These expenditures are planned to be financed by cash onhand and cash generated from operations.

Other Commitments

SCE has an unconditional purchase obligation for firm transmission service from another utility. Minimumpayments are based, in part, on the debt-service requirements of the transmission service provider, whether ornot the transmission line is operable. The contract requires minimum payments of $60 million through 2016(approximately $7 million per year).

At December 31, 2008, EME and its subsidiaries were party to a long-term power purchase contract, a coalcleaning agreement, turbine operations and maintenance agreements, and agreements for the purchase oflimestone, ammonia, and materials for environmental controls equipment.

As of December 31, 2008, standby letters of credit aggregated $133 million and were scheduled to expire in2009.

Guarantees and Indemnities

Edison International’s subsidiaries have various financial and performance guarantees and indemnificationswhich are issued in the normal course of business. As discussed below, these contracts included performanceguarantees, guarantees of debt and indemnifications.

Tax Indemnity Agreements

In connection with the sale-leaseback transactions related to the Homer City facilities in Pennsylvania, thePowerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of itssubsidiaries entered into tax indemnity agreements. Although the Collins Station lease terminated in April2004, Midwest Generation’s tax indemnity agreement with the former lease equity investor is still in effect.Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leasebacktransactions for specified adverse tax consequences that could result in certain situations set forth in each taxindemnity agreement, including specified defaults under the respective leases. The potential indemnityobligations under these tax indemnity agreements could be significant. Due to the nature of these potentialobligations, EME cannot determine a maximum potential liability which would be triggered by a valid claimfrom the lessors. EME has not recorded a liability related to these indemnities.

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Indemnities Provided as Part of the Acquisition of the Illinois Plants

In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edisonwith respect to specified environmental liabilities before and after December 15, 1999, the date of sale. Theindemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and aresubject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to anysuch indemnification claim. Due to the nature of the obligation under this indemnity, a maximum potentialliability cannot be determined. This indemnification for environmental liabilities is not limited in term andwould be triggered by a valid claim from Commonwealth Edison. Commonwealth Edison has advised EMEthat Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses thatit may be required to bear as a result of the NOV discussed under “EMG: Other Developments — MidwestGeneration New Source Review Notice of Violation” and potential litigation by private groups related to theNOV. Except as discussed below, EME has not recorded a liability related to this indemnity.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and ExelonGeneration on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligationfor asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under thissupplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and ExelonGeneration for 50% of specific asbestos claims pending as of February 2003 and related expenses lessrecovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated withfuture asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison andMidwest Generation apportion responsibility for future asbestos-related claims based upon the number ofexposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligationsunder this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of eitherparty to terminate); pursuant to the automatic renewal provision, it has been extended until February 2010.There were approximately 222 cases for which Midwest Generation was potentially liable and that had notbeen settled and dismissed at December 31, 2008. Midwest Generation had recorded a $52 million liability atDecember 31, 2008 related to this matter.

Midwest Generation recorded an undiscounted liability for its indemnity for future asbestos claims through2045. During the fourth quarter of 2007, the liability was reduced by $9 million based on updated estimatedlosses. In calculating future losses, various assumptions, were made including but not limited to, the settlementof future claims under the supplemental agreement with Commonwealth Edison as described above, thedistribution of exposure sites, and that no asbestos claims will be filed after 2044.

The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number ofassumptions. Future events, such as the number of new claims to be filed each year, the average cost ofdisposing of claims, as well as the numerous uncertainties surrounding asbestos litigation in the United States,could cause the actual costs to be higher or lower than projected.

Indemnity Provided as Part of the Acquisition of the Homer City Facilities

In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify thesellers with respect to specific environmental liabilities before and after the date of sale. Payments would betriggered under this indemnity by a valid claim from the sellers. EME guaranteed the obligations of EMEHomer City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximumpotential liability and does not have an expiration date. See “EMG: Other Developments — EME Homer CityNew Source Review Notice of Violation” for discussion of the NOV received by EME Homer City andassociated indemnity claims. EME has not recorded a liability related to this indemnity.

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Indemnities Provided under Asset Sale Agreements

The asset sale agreements for the sale of EME’s international assets contain indemnities from EME to thepurchasers, including indemnification for taxes imposed with respect to operations of the assets prior to thesale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements havespecific expiration dates. Payments would be triggered under these indemnities by valid claims from thesellers or purchasers, as the case may be. At December 31, 2008 and 2007, EME had recorded a liability of$95 million (of which $51 million is classified as a current liability) related to these matters.

In connection with the sale of various domestic assets, EME has from time to time provided indemnities to thepurchasers for taxes imposed with respect to operations of the asset prior to the sale. EME has also providedindemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigationmatters and/or environmental conditions). Due to the nature of the obligations under these indemnityagreements, a maximum potential liability cannot be determined. Not all indemnities under the asset saleagreements have specific expiration dates. Payments would be triggered under these indemnities by validclaims from the sellers or purchasers, as the case may be. At December 31, 2008, EME had recorded aliability of $13 million related to these matters.

Capacity Indemnification Agreements

As of December 31, 2008, EME has a 50% interest in the March Point project. EME has guaranteed, jointlyand severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project powersales agreements to repay capacity payments to the project’s power purchaser in the event that the power salesagreements terminate, March Point Cogeneration Company abandons the project, or the project fails to returnto normal operations within a reasonable time after a complete or partial shutdown, during the term of thepower sales agreements. The obligations under this indemnification agreement as of December 31, 2008, ifpayment were required, would be $56 million, which is EME’s maximum exposure to loss as EME fullyimpaired its equity investment in the project in 2005. EME has not recorded a liability related to theindemnity.

Indemnity Provided as Part of the Acquisition of Mountainview

In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect tospecific environmental claims related to SCE’s previously owned San Bernardino Generating Station, divestedby SCE in 1998 and reacquired as part of the Mountainview acquisition. SCE retained certain responsibilitieswith respect to environmental claims as part of the original divestiture of the station. The aggregate liabilityfor either party to the purchase agreement for damages and other amounts is a maximum of $60 million. Thisindemnification for environmental liabilities expires on or before March 12, 2033. SCE has not recorded aliability related to this indemnity.

Mountainview Filter Cake Indemnity

Mountainview owns and operates a power plant in Redlands, California. The plant utilizes water from on-sitegroundwater wells and City of Redlands (City) recycled water for cooling purposes. Unrelated to the operationof the plant, this water contains perchlorate. The pumping of the water removes perchlorate from the aquiferbeneath the plant and concentrates it in the plant’s wastewater treatment “filter cake.” Use of this impactedgroundwater for cooling purposes was mandated by Mountainview’s California Energy Commission permit.Mountainview has indemnified the City for cleanup or associated actions related to groundwater contaminatedby perchlorate due to the disposal of filter cake at the City’s solid waste landfill. The obligations under thisagreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded aliability related to this guarantee.

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Other Edison International Indemnities

Edison International provides other indemnifications through contracts entered into in the normal course ofbusiness. These are primarily indemnifications against adverse litigation outcomes in connection withunderwriting agreements, and specified environmental indemnities and income taxes with respect to assetssold. Edison International’s obligations under these agreements may be limited in terms of time and/oramount, and in some instances Edison International may have recourse against third parties for certainindemnities. The obligated amounts of these indemnifications often are not explicitly stated, and the overallmaximum amount of the obligation under these indemnifications cannot be reasonably estimated. EdisonInternational has not recorded a liability related to these indemnities.

OFF-BALANCE SHEET TRANSACTIONS

This section of the MD&A discusses off-balance sheet transactions at EMG. SCE does not have off-balancesheet transactions. Included are discussions of investments accounted for under the equity method for bothsubsidiaries, as well as sale-leaseback transactions at EME, EME’s obligations to one of its subsidiaries, andleveraged leases at Edison Capital.

Investments Accounted for under the Equity Method

EME has a number of investments in power projects that are accounted for under the equity method. Underthe equity method, the project assets and related liabilities are not consolidated on EME’s consolidatedbalance sheet. Rather, EME’s financial statements reflect its investment in each entity and it records only itsproportionate ownership share of net income or loss.

Historically, EME has invested in qualifying facilities, those which produce electrical energy and steam, orother forms of energy, and which meet the requirements set forth in PURPA. Prior to the passage of the EPAct2005, these regulations limited EME’s ownership interest in qualifying facilities to no more than 50% due toEME’s affiliation with SCE, a public utility. For this reason, EME owns a number of domestic energy projectsthrough partnerships in which it has a 50% or less ownership interest.

Entities formed to own these projects are generally structured with a management committee or board ofdirectors in which EME exercises significant influence but cannot exercise unilateral control over theoperating, funding or construction activities of the project entity. In certain projects, long-term debt to financethe assets constructed was secured. These financings generally are secured by a pledge of the assets of theproject entity, but do not provide for any recourse to EME. Accordingly, a default on a long-term financing ofa project could result in foreclosure on the assets of the project entity resulting in a loss of some or all ofEME’s project investment, but would generally not require EME to contribute additional capital. AtDecember 31, 2008, entities which EME has accounted for under the equity method had indebtedness of$294 million, of which $128 million is proportionate to EME’s ownership interest in these projects.

Edison Capital has invested in affordable housing projects utilizing partnership or limited liability companiesin which Edison Capital is a limited partner or limited liability member. In these entities, Edison Capitalusually owns a 99% interest. With a few exceptions, an unrelated general partner or managing memberexercises operating control; voting rights of Edison Capital are limited by agreement to certain significantorganizational matters. Edison Capital has subsequently sold a majority of these interests to unrelated thirdparty investors through syndication partnerships in which Edison Capital has retained an interest, with oneexception, of less than 20%. The debt of those partnerships and limited liability companies is secured by realproperty and is nonrecourse to Edison Capital, except in limited cases where Edison Capital has guaranteedthe debt. At December 31, 2008, Edison Capital had made guarantees to lenders in the amount of$1.4 million.

Edison Capital has also invested in three limited partnership funds which make investments in infrastructureand infrastructure-related projects. Those funds follow special investment company accounting which requires

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the fund to account for its investments at fair value. Although Edison Capital would not follow specialinvestment company accounting if it held the funds’ investment directly, Edison Capital records itsproportionate share of the funds’ results as required by the equity method.

At December 31, 2008, entities that Edison Capital has accounted for under the equity method hadindebtedness of approximately $1.5 billion, of which approximately $648 million is proportionate to EdisonCapital’s ownership interest in these projects. Substantially all of this debt is nonrecourse to Edison Capital.

Sale-Leaseback Transactions

EME has entered into sale-leaseback transactions related to the Powerton Station and Units 7 and 8 of theJoliet Station in Illinois and the Homer City facilities in Pennsylvania. For further discussion, see “EdisonInternational: Management Overview,” “Critical Accounting Estimates and Policies — Off-Balance SheetFinancing” and “Commitments, Guarantees and Indemnities — Operating and Capital Leases.”

EME’s subsidiaries account for these leases as financings in their separate financial statements due to specificguarantees provided by EME or another one of its subsidiaries as part of the sale-leaseback transactions. Theseguarantees do not preclude EME from recording these transactions as operating leases in its consolidatedfinancial statements, but constitute continuing involvement under SFAS No. 98 that precludes EME’ssubsidiaries from utilizing this accounting treatment in their separate subsidiary financial statements. Instead,each subsidiary continues to record the power plants as assets in a similar manner to a capital lease andrecords the obligations under the leases as lease financings. EME’s subsidiaries, therefore, record depreciationexpense from the power plants and interest expense from the lease financing in lieu of an operating leaseexpense which EME uses in preparing its consolidated financial statements. The treatment of these leases asan operating lease in its consolidated financial statements in lieu of a lease financing, which is recorded byEME’s subsidiaries, resulted in an increase in consolidated net income of $46 million, $54 million and$61 million in 2008, 2007 and 2006, respectively.

The lessor equity and lessor debt associated with the sale-leaseback transactions for the Powerton, Joliet andHomer City assets are summarized in the following table:

PowerStation(s)

AcquisitionPrice Equity Investor

Original EquityInvestment inOwner/Lessor(In millions)

Amount ofLessor Debt atDecember 31,

2008

MaturityDate ofLessorDebt

Powerton/Joliet $ 1,367 PSEG/Citigroup, Inc. $ 238 $ 119 Series A 2009679 Series B 2016

Homer City 1,591 GECC/ Metropolitan 798 $ 237 Series A 2019Life Insurance 510 Series B 2026

Company

PSEG — PSEG Resources, Inc.GECC — General Electric Capital Corporation

The operating lease payments to be made by each of EME’s subsidiary lessees are structured to service thelessor debt and provide a return to the owner/lessor’s equity investors. Neither the value of the leased assetsnor the lessor debt is reflected on EME’s consolidated balance sheet. In accordance with GAAP, EME records

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rent expense on a levelized basis over the terms of the respective leases. The following table summarizes thelease payments and rent expense for the three years ended December 31, 2008.


Cash payments under plant operating leasesPowerton and Joliet facilities $ 185 $ 185 $ 185Homer City facilities 152 151 152

Total cash payments under plant operating leases $ 337 $ 336 $ 337

Rent expensePowerton and Joliet facilities $ 75 $ 75 $ 75Homer City facilities 102 102 102

Total rent expense $ 177 $ 177 $ 177

To the extent that EME’s cash rent payments exceed the amount levelized over the term of each lease, EMErecords prepaid rent. At December 31, 2008 and 2007, prepaid rent on these leases was $878 million and$716 million, respectively. To the extent that EME’s cash rent payments are less than the amount levelized,EME reduces the amount of prepaid rent.

In the event of a default under the leases, each lessor can exercise all its rights under the applicable lease,including repossessing the power plant and seeking monetary damages. Each lease sets forth a terminationvalue payable upon termination for default and in certain other circumstances, which generally declines overtime and in the case of default may be reduced by the proceeds arising from the sale of the repossessed powerplant. A default under the terms of the Powerton and Joliet or Homer City leases could result in a loss ofEME’s ability to use such power plant and would trigger obligations under EME’s guarantee of the Powertonand Joliet leases. These events could have a material adverse effect on EME’s results of operations andfinancial position.

EME’s minimum lease obligations under its power related leases are set forth under “— ContractualObligations, Commitments and Contingencies — Contractual Obligations — Operating Lease Obligations.”

Leveraged Leases

Edison Capital is the lessor in various power generation, electric transmission and distribution, transportationand telecommunications leases. The debt in these leveraged leases is nonrecourse to Edison Capital and is notrecorded on Edison International’s balance sheet in accordance with SFAS No. 13, “Accounting for Leases.”

At December 31, 2008, Edison Capital had net investments, before deferred taxes, of $2.5 billion in itsleveraged leases, with nonrecourse debt in the amount of $5.0 billion. As further described in “OtherDevelopments — Federal and State Income Taxes,” the IRS has raised issues in the audit of EdisonInternational’s tax returns with respect to certain leveraged leases at Edison Capital.

OTHER DEVELOPMENTS

Environmental Matters

The operating subsidiaries of Edison International are subject to numerous federal and state environmentallaws and regulations, which require them to incur substantial costs to operate existing facilities, construct andoperate new facilities, and mitigate or remove the effect of past operations on the environment. EdisonInternational believes that its operating subsidiaries are in substantial compliance with existing environmentalregulatory requirements. However, the US EPA has issued a NOV to Midwest Generation and CommonwealthEdison, the former owner of Midwest Generation’s coal-fired power plants, alleging violations of the CAA andcertain opacity and particulate matter standards. For information on the US EPA NOV issued to Midwest

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Generation, see “EMG: Other Developments — Midwest Generation Potential Environmental Proceeding”above.

The domestic power plants owned or operated by Edison International’s operating subsidiaries, in particulartheir coal-fired plants, may be affected by recent developments in federal and state environmental laws andregulations. These laws and regulations, including those relating to SO2 and NOx emissions, mercuryemissions, ozone and fine particulate matter emissions, regional haze, water quality, and climate change, mayrequire significant capital expenditures at these facilities. The developments in certain of these laws andregulations are discussed in more detail below. These developments will continue to be monitored to assesswhat implications, if any, they will have on the operation of domestic power plants owned or operated bySCE, EME, or their subsidiaries, or the impact on Edison International’s consolidated results of operations orfinancial position.

Climate Change

Federal Legislative Initiatives

Currently a number of bills are proposed or under discussion in Congress to mandate reductions of GHGemissions. At this point, it cannot be determined whether any of these proposals will be enacted into law or toestimate their potential effect on the operations of Edison International’s subsidiaries. The ultimate outcome ofthe debate about GHG emission regulation on the federal level could have a significant economic effect on theoperations of Edison International’s subsidiaries. Any legal obligation that would require a substantialreduction in emissions of carbon dioxide or would impose additional costs or charge for the emission ofcarbon dioxide could have a materially adverse effect on operations.

These costs will depend upon many factors, including the required levels of GHG emission reductions, thetiming of those reductions, the impact on fuel prices, whether emissions will be taxed or emission credits willbe allocated with or without cost to existing generators, and whether flexible compliance mechanisms, such asa GHG offset program similar to those sanctioned under the CAA for conventional pollutants, will be part ofthe policy.

While debate continues at the national level over domestic climate policy and the appropriate scope and termsof any federal legislation, many states are developing state-specific measures or participating in regionallegislative initiatives to reduce GHG emissions.

Edison International supports a national regulatory program for GHG emission reduction that is market-based,equitable and comprehensive, through which all sources of GHG emissions are regulated and all certifiablemeans of reducing and offsetting such emissions are recognized. This program should be long-term, andshould establish technologically realistic GHG emission reduction targets.

Regional Initiatives

On December 20, 2005, seven northeastern states entered into a Memorandum of Understanding to create aregional initiative to establish a-cap-and trade GHG program for electric generators, referred to as theRegional Greenhouse Gas Initiative (RGGI). In August 2006, the participating states issued a model rule to beused as a basis for individual state legislative and regulatory action to implement the program. The RGGIstates (now numbering ten states) have passed laws and/or regulations to implement the RGGI program, whichcommenced in 2009. Pennsylvania is not a signatory to the RGGI, although it has participated as an observerof the process.

In February 2007, the Governors of Arizona, California, New Mexico, Oregon and Washington launched theWestern Climate Initiative to develop regional strategies to address climate change. The Western ClimateInitiative is identifying, evaluating and implementing collective and cooperative ways to reduce greenhousegases in the region. Since February 2007, the Governor of Utah and Montana and the Premiers of BritishColumbia, Manitoba, Ontario and Quebec have joined the Initiative. Other states and provinces have joined as

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observers. The Initiative partners set an overall regional goal in August 2007 for reducing GHG emissions to15% below 2005 levels by 2020. In September 2008, the partners released design recommendations for theregional cap-and-trade program intended to help achieve that reduction goal.

On November 15, 2007, Illinois became a party to the Midwestern Accord, in which six of the twelve states inthe Midwestern Governors’ Association, including Illinois, agreed to seek to develop regional GHG emissionreduction goals within one year, and to develop a multi-sector cap-and-trade program to achieve these goals.The Accord called for such a program to be implemented in 30 months. On February 19, 2008, the sixparticipating states announced that they would complete a model rule by the end of 2008 that would create theframework for the cap-and-trade program. The schedule for the model rule has been revised to fall 2009. Oncethis model rule has been drafted, each of the participating states could adopt the program through legislativeaction, executive order or other appropriate means. In February 2007, prior to the development of theMidwestern Accord, then-Illinois Governor Blagojevich announced a goal to reduce Illinois’ GHG emissionsto 1990 levels by 2020 and to 60% below 1990 levels by 2050.

Implementing regulations for such regional initiatives are likely to vary from state to state and may be morestringent and costly than federal legislative proposals currently being debated in Congress. It cannot yet bedetermined whether or to what extent any federal legislative system would seek to preempt regional or stateinitiatives, although such preemption would greatly simplify compliance and eliminate regulatory duplication.

State-Specific Legislation

In September 2006, California enacted two laws regarding GHG emissions. The first, known as AB 32 or theCalifornia Global Warming Solutions Act of 2006, establishes a comprehensive program to begin in 2012 toachieve reductions of GHG emissions. The second law, known as SB 1368, required the CPUC and the CEC,respectively, to adopt GHG emission performance standards, known as EPS, for investor owned and publiclyowned utilities, respectively, for long-term procurement of electricity. These standards must equal theperformance of a combined-cycle gas turbine generator.

AB 32 required the CARB to approve a scoping plan for achieving the maximum technologically feasible andcost-effective reductions in GHG emissions on or before January 1, 2009. On December 11, 2008, the CARBapproved a proposed scoping plan which was largely unchanged from the original draft scoping plan that wasreleased in June 2008. However, the revised draft scoping plan does not include the more aggressive energyefficiency or coal emission reduction standard measures that were under evaluation for inclusion in theproposed draft scoping plan. The preliminary recommendations in the proposed scoping plan included: aCalifornia cap-and-trade program linked to the Western Climate Initiative covering electricity, transportation,residential/commercial, and industrial sources by 2020; California light-duty vehicle GHG standards; increasedenergy efficiency, including increasing combined heat and power use; a 33% by 2020 Renewables PortfolioStandard for both Investor-Owned Utilities and publicly-owned utilities; a low-carbon fuel standard; measuresto reduce high global warming potential gases; sustainable forest measures; water sector measures; vehicleefficiency measures, goods movement measures; heavy/medium duty vehicle measures; the Million SolarRoofs program; local government actions and regional targets; supporting implementation of a high-speed railsystem; recycling and waste measures; agriculture measures; and energy efficiency and co-benefits audits forlarge industrial sources.

In October 2008, the CPUC and CEC adopted a proposed opinion on GHG regulatory strategies providingadditional recommendations to the CARB on measures and strategies for reducing GHG emissions in theelectricity and natural gas sectors. The proposed opinion’s recommendations address mandatory emissionreduction measures including energy efficiency, renewable resources, and expansion of combined heat andpower. The recommendations also include design suggestions for a multi-sector, statewide, cap-and-tradeprogram. The Los Angeles Department of Water and Power filed a request for rehearing and reconsiderationof the opinion with the CPUC and CEC on November 21, 2008.

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AB 32 also required the CARB to adopt regulations requiring the reporting and verification of statewide GHGemissions on or before January 1, 2008. On December 6, 2007 the CARB approved regulations for themandatory reporting of GHG emissions, including the reporting of GHG emissions for the electricity sector.The CARB directed its staff to make some technical modifications to the proposed regulations, which hadbeen issued in October 2007. The CARB staff issued revised regulations for public comment on May 15 andJune 30, 2008. The final regulations became effective on January 1, 2009. SCE and EME are evaluating theCARB’s reporting regulations and the scoping plan under AB 32 to assess the total cost of compliance.

The emission performance standards adopted by the CPUC and CEC pursuant to SB 1368 prohibit SCE andother California load-serving entities from entering into long-term financial commitments with generators thatemit more than 1,100 pounds of CO2 per MWh, which would include most coal-fired plants. In January 2008,SCE filed a petition with the CPUC seeking clarification that the emission performance standard would notapply to capital expenditures required by existing agreements among the owners at Four Corners. The CPUCissued a proposed decision finding that the emission performance standard was not intended to apply to capitalexpenditures at Four Corners requested by SCE in its GRC for the period 2007 – 2011. In October 2008, theAssigned Commissioner and Administrative Law Judge issued a ruling withdrawing the proposed decision andseeking additional comment on whether the finding in the proposed decision should be changed and whetherSCE should be allowed to recover such capital expenditures. SCE estimates that its share of capitalexpenditures approved by the owners at Four Corners since the GHG emission performance standard decisionwas issued in January 2007 is approximately $43 million, of which approximately $8 million had beenexpended through December 31, 2008. The ruling also directs SCE to explain why certain information was notincluded in its petition and why the failure to include such information should not be considered misleading inviolation of CPUC rules. SCE filed its response and comments to the ruling in November and December 2008and cannot predict the outcome of this proceeding or estimate the amount, if any, of penalties or disallowancesthat may be imposed.

Litigation Developments

Significant climate change litigation, raising issues that may affect the timing and scope of future GHGemission regulation, was brought by a variety of public and private parties in the past several years. As nodecisions were handed down in any of the major cases in 2008, it continues to be difficult to determine howthe courts will respond to every situation. To date, trial courts that have addressed the cases in which plaintiffshave sought damages or equitable relief directly from power companies and other defendants have dismissedthe plaintiff’s claims, either because the courts determined that a judicial decision would impermissibly intrudeon the powers of the legislative and executive branches to regulate and, as applicable, enter into foreigncompacts concerning GHG emissions, or because of the absence of evidence linking any individualdefendant’s GHG emissions to any harm allegedly incurred by the suing plaintiffs.

On April 2, 2007, the United States Supreme Court issued an opinion in Massachusetts et. al. v.Environmental Protection Agency, et. al., ruling that the US EPA has the authority to regulate GHG emissionsof new motor vehicles under the CAA and that it has a duty to determine whether GHG emissions of newmotor vehicles contribute to climate change or offer a reasoned explanation for its failure to make such adetermination when presented with a request for a rulemaking on the issue by the state claimants. The Courtruled that the US EPA’s failure to make the necessary determination or to offer a reasonable explanation for itsrefusal to do so was impermissible. While this case hinged on a provision of the CAA related to emissions ofmotor vehicles, a parallel provision of the CAA applies to stationary sources, such as electric generators, andthere is litigation pending in the D.C. Circuit Court of Appeals, Coke Oven Task Force v. EPA, in which it isargued that the Massachusetts v. EPA case may be applied to stationary sources such as power plants.

In April 2006, private citizens filed a complaint in federal court in Mississippi against numerous defendants,including Edison International and several electric utilities, arguing that emissions from the defendants’facilities contributed to climate change and seeking monetary damages related to the 2005 hurricane season. InAugust 2007, the court dismissed the case, and plaintiffs have appealed this dismissal to the Fifth Circuit

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Court of Appeals. In February 2008, a native Alaskan village and city filed a complaint in federal court inCalifornia against 24 defendants, including Edison International, who directly or through subsidiaries engagein electric generating, oil and gas, or coal mining lines of business. The complaint contends that the allegedglobal warming impacts of the GHG emissions associated with the defendants’ business activities aredestroying the plaintiffs’ village through the melting of Arctic ice that had previously protected the villagefrom winter storms. The plaintiffs further allege that the village will soon need to be abandoned or relocated ata cost of between $95 million and $400 million. Motions to dismiss the complaint in the California case arecurrently pending and Edison International cannot predict the outcome of this lawsuit.

Air Quality Regulation

Clean Air Interstate Rule

The CAIR, issued by the US EPA on March 10, 2005, applies to 28 eastern states (including Illinois andPennsylvania) and the District of Columbia, and is intended to address ozone and fine particulate matterattainment issues by reducing regional SO2 and NOx emissions. The CAIR reduces the current CAA Title IVPhase II SO2 emission allowance cap for 2010 and 2015 by 50% and 65%, respectively. The CAIR alsorequires reductions in regional NOx emissions in 2009 and 2015 by 53% and 61%, respectively, from 2003levels. Both Illinois and Pennsylvania have developed SIPs to meet CAIR requirements. The Illinois andPennsylvania SIPs for the CAIR, with the exception for set-asides of NOx allowances in Illinois, substantivelymatched the federal CAIR requirements.

In December 2008, the District of Columbia Circuit Court of Appeals remanded the CAIR to the US EPA,without vacating the rule, but with instructions that the US EPA remedy CAIR’s flaws in accordance with anearlier opinion of the Court in the same case. That opinion raised significant questions as to whether the USEPA could use cap-and-trade programs for NOx and SO2 to remedy upwind contributions to downwind states’noncompliance with national ambient air quality standards for ozone and fine particulate matter. The practicalimpact of the remand is that CAIR requirements became effective January 1, 2009 and are to remain in placeuntil the US EPA promulgates a revised rule. The timing and substance of the revised rule are not yet clear.There is substantial uncertainty as to how and when the US EPA will address the deficiencies identified by theCourt and the impact revised regulations will have on SIPs promulgated to implement the CAIR. In addition,the US EPA has allowed states to rely on compliance with the CAIR to satisfy obligations under other CAAprograms, including regional haze regulations and reasonably available control technology requirements.Depending on what happens with respect to the CAIR and the revised SIPs developed as a consequence of theCAIR, the Illinois Plants and the Homer City facilities may be subject to additional requirements pursuant tothese programs.

The Illinois Plants continue to be subject to the CAIR. EME expects that compliance with the CAIR, andrevised or additional state regulations promulgated to comply with a revised CAIR and/or other air regulatoryrequirements, could result in increased capital expenditures and operating expenses beyond those alreadyrequired by the CPS, discussed below.

Illinois

Under the CPS, Midwest Generation is required to achieve specific lower emission rates by specified dates.Midwest Generation has not decided upon a particular combination of retrofits to meet the required step downin emission rates. Midwest Generation continues to review alternatives, including interim compliancesolutions. The CPS also specifies that specific control technologies are to be installed on some units byspecified dates. In these cases, Midwest Generation must either install the required technology by the specifieddeadline or shut down the unit.

In order to comply with the CPS, Midwest Generation shut down Unit 6 at the Waukegan Station onDecember 31, 2007 and must permanently shut down Units 1 and 2 at the Will County Station byDecember 31, 2010.

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The principal emission standards and control technology requirements for NOx and SO2 under the CPS are asdescribed below:

NOx Emissions – Beginning in calendar year 2012 and continuing in each calendar year thereafter, MidwestGeneration must comply with an annual and seasonal NOx emission rate of no more than 0.11 lbs/million Btu.In addition to these standards, Midwest Generation must install and operate SNCR equipment on Units 7 and8 at the Crawford Station by December 31, 2015.

Midwest Generation is in the process of completing engineering work for the potential installation of SCRequipment on Units 5 and 6 at the Powerton Station and SNCR equipment on Unit 6 at the Joliet Station. TheSCR equipment at the Powerton Station is currently estimated to cost $500 million, and the SNCR equipmenton Unit 6 at the Joliet Station is currently estimated to cost $13 million (both figures are in 2008 dollars).This technology combination represents one possible compliance plan for the NOx emission rate. MidwestGeneration is evaluating other potential solutions that are less costly to meet the NOx emission rate thatcombine the use of alternative NOx removal technologies with certain unit shutdowns.

SO2 Emissions – Midwest Generation must comply with an overall SO2 annual emission rate of:

• 0.44 lbs/million Btu in 2013






• 0.11 lbs/million Btu in 2019 and thereafter

In addition to these standards, Midwest Generation must install and operate the following specific emissioncontrol technologies by the dates indicated:

• FGD equipment on Unit 7 and Unit 8 at the Waukegan Station by December 31, 2013 and December 31,2014, respectively.

• FGD equipment on Unit 19 at the Fisk Station by December 31, 2015.

• FGD equipment on Unit 8 and Unit 7 at the Crawford Station by December 31, 2017 and December 31,2018, respectively.

• FGD equipment on Units 7 and 8 at the Joliet Station, Units 5 and 6 at the Powerton Station, andUnits 3 and 4 at the Will County Station by December 31, 2018.

The engineering work at the Powerton Station also included the potential installation of FGD equipment onUnits 5 and 6, and Midwest Generation currently estimates approximately $1 billion (in 2008 dollars) ofcapital expenditures would be required for the FGD equipment at the Powerton Station. Midwest Generationalso determined these capital expenditures could be reduced if the construction work sequence of FGD andSCR at the Powerton Station were reversed. The complexity of the Powerton Station installation andconstruction interferences are representative of the balance of the fleet and Midwest Generation currentlyestimates approximately $650/kW for any FGD installation it elects to make on other units.

Changes in the cost of labor, equipment, and materials, among other factors, may materially affect the aboveestimates for SCR, SNCR and FGD equipment.

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Compliance Costs and Plans

Decisions to install the improvements described above have not been made. Midwest Generation is stillreviewing all technology and unit shutdown combinations, including interim and alternative compliancesolutions. These decisions will take into account many factors, including, among others, the effectiveness andcost of various control technologies, the remaining estimated useful life of each affected unit, the marketoutlook for the prices of various commodities, including electrical energy and capacity, coal and natural gas,availability of financing, and the statutory and regulatory environment including potential GHG regulation.Under current uncertain conditions, Midwest Generation cannot predict the extent to which its interim or long-term compliance with the CPS will result in the retrofit or temporary or permanent suspension or eventualshutdown of a material part of its operating units.

Pennsylvania

On December 18, 2007, the Pennsylvania Environmental Quality Board approved the Pennsylvania CAIR.This rule has been submitted to the US EPA for approval as part of the Pennsylvania SIP. The PennsylvaniaCAIR is substantively similar to the CAIR. EME Homer City will be subject to the federal CAIR rule during2009 and expects to be able to comply with the NOx requirement using its existing SCR system. ThePennsylvania CAIR, including both NOx and SO2 limits, is expected to become effective in 2010. EMEHomer City expects to comply with Pennsylvania CAIR through the continued operation of its scrubber onUnit 3 to reduce SO2 emissions and the purchase of SO2 allowances.

Clean Air Mercury Rule

By means of a rule published in May 2005, the US EPA established the CAMR, which created the frameworkfor a national, market-based cap-and-trade program to reduce mercury emissions from existing coal-firedpower plants to a national cap of 38 tons by 2010 and to 15 tons by 2018, primarily through reductions inmercury achieved by lowering SO2 and NOx emissions under the CAIR. States were allowed, but not required,to join the trading program by adopting the CAMR model trading rules. States retained the right to promulgatealternative regulations equivalent to or more stringent than the CAMR cap-and-trade program, as long as theregulations were approved by the US EPA.

At the time that it published the CAMR, the US EPA also published a second rule, formally rescinding itsprevious finding that mercury emissions from electrical generating facilities had to be regulated as a hazardousair pollutant pursuant to Section 112 of the CAA, which would have imposed technology-based standards onemission sources. Both the CAMR and US EPA’s decision to remove oil-and coal-fired plants from the lists ofsources to be regulated under Section 112 of the CAA were challenged in the U.S. Court of Appeals for theD.C. Circuit by various environmental groups and state attorneys general.

On February 8, 2008, the D.C. Circuit Court of Appeals vacated both rules and remanded the matter to the USEPA. The United States and the Utility Air Regulatory Group had petitioned the Supreme Court to review theD.C. Circuit’s decision, but the United States subsequently filed a motion to withdraw its petition based on adetermination by the US EPA to develop a new mercury regulation pursuant to Section 112 of the CAA. TheUtility Air Regulatory Group has not withdrawn its petition. The order has been appealed to the U.S. SupremeCourt. Until the US EPA takes action in response to the remand, coal-fired electrical generating units willcontinue to be sources subject to the requirements of Section 112 of the CAA and will be obligated to comply,on a case-by-case basis, with technology-based standards to control emissions of all hazardous air pollutants(not necessarily limited to mercury) in accordance with the requirements of Section 112. On February 23,2009, the U.S. Supreme Court declined to review the D.C. Circuit’s decision.

Regional Haze

In July 1999, the US EPA published the “Regional Haze Rule” to reduce haze and protect visibility indesignated federal areas. The goal of the 1999 rule is to restore visibility in mandatory federal Class I areas,

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such as national parks and wilderness areas, to natural background conditions by 2064. Sources such as powerplants that are reasonably anticipated to contribute to visibility impairment in Class I areas may be required toinstall Best Available Retrofit Technology (also known as BART) or implement other control strategies tomeet regional haze control requirements.

States were required to revise their SIPs by December 2007 to demonstrate reasonable further progresstowards meeting regional haze goals. On January 9, 2009, the US EPA found that 37 states, includingCalifornia, Illinois, Nevada, and Pennsylvania, had failed to submit all or a portion of their regional haze SIPs.For those states that have yet to make a submission, or that have made a submission that does not includeparticular SIP elements, EPA is making a “finding of failure to submit.” The US EPA finding initiates a 2-yeardeadline for EPA to issue a Federal Implementation Plan or FIP. The FIP will provide the basic programrequirements for each State that has not completed an approved plan of its own by January 15, 2011. It ispossible that sources subject to the CAIR will be able to satisfy their obligations under the regional hazeregulations through compliance with the CAIR although, as previously noted, the D.C. Circuit Court’s decisionto remand the CAIR to the US EPA means that there is substantial uncertainty as to the future of the federaland state CAIR programs. However, until the SIPs are revised, EME cannot predict whether it will be requiredto install BART or implement other control strategies, and cannot identify the financial impacts of anyadditional control requirements.

The CPS, discussed above in “— Clean Air Interstate Rule — Illinois,” addresses emissions reductions atBART affected sources. In Pennsylvania, the PADEP considers the CAIR to meet the BART requirements, andthe Homer City facilities are only required to consider reductions in emissions of suspended particulate matter(PM10), which at this time are being evaluated by the state.

The US EPA has adopted alternate rules for the area where Four Corners is located. The rules allow ninewestern states and Native American tribes to follow an alternate implementation plan and schedule for theClass I Areas. This alternate implementation plan is known as the Annex Rule. The US EPA issued a RevisedAnnex Rule on October 13, 2006, to address a previous challenge and court remand of that rule.

New Mexico

The Regional office of the US EPA (EPA Region 9) requested that Arizona Public Service Company performa BART analysis for Four Corners. This analysis was completed and submitted it to the US EPA onJanuary 30, 2008. The EPA Region 9 will review Arizona Public Service Company’s submission anddetermine what constitutes BART for Four Corners. Once Arizona Public Service Company receives the EPARegion 9’s final determination, it will have five years to complete the installation of the equipment, ifrequired, and to achieve the emission limits established by the EPA Region 9. Until the EPA Region 9 makesa final determination on this matter, SCE cannot accurately estimate the expenditures that may be required.SCE also cannot predict whether the relevant environmental agencies will agree with its BARTrecommendations or, if the agencies disagree with our recommendations, the nature of the BART controls theagencies may ultimately mandate and the resulting financial or operational impact. In addition, SCE cannotpredict whether or not CPUC regulations will permit it to make investments in equipment that may berequired.

New Source Review Requirements

Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address CAANSR compliance issues at the nation’s coal-fired power plants. The NSR regulations impose certainrequirements on facilities, such as electric generating stations, if modifications are made to air emissionssources at a facility. The US EPA’s strategy has included both the filing of suits against a number of powerplant owners, and the issuance of administrative NOVs to a number of power plant owners alleging NSRviolations. See “EMG: Other Developments — Midwest Generation New Source Review Notice of Violation”

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and “EMG: Other Developments — EME Homer City New Source Review Notice of Violation” for furtherdiscussion.

Ambient Air Quality Standards

The US EPA designated non-attainment areas for its 8-hour ozone standard on April 30, 2004, and for its fineparticulate matter standard on January 5, 2005. States were required to revise their SIPs for the ozone andparticulate matter standards within three years of the effective date of the respective non-attainmentdesignations. Since then, the US EPA has issued more stringent 24-hour fine particulate and ground levelozone standards. The revised SIPs are likely to require additional emission reductions from facilities that aresignificant emitters of ozone precursors and particulates. Edison International anticipates that further emissionreduction obligations will not be imposed under these revised ambient air quality standards until 2015.

Priority Reserve Legal Challenges

In July 2008, the Los Angeles Superior Court found that actions taken by the SCAQMD, in promulgatingrules that had made available a “Priority Reserve” of emissions credits for new power generation projects didnot satisfy California environmental laws. In November 2008, the Los Angeles Superior Court enjoined theSCAQMD from issuing Priority Reserve emission credits to any facility, including new power projects, until asatisfactory environmental analysis is completed. The writ also ordered the SCAQMD to refrain from takingany action relating to power plant projects approved after August 2007 pursuant to the Priority Reserve rulesuntil the SCAQMD completes a satisfactory environmental analysis. The SCAQMD appealed the SuperiorCourt decision, and in doing so, stayed the injunction against the issuance of permits.

In a letter dated January 9, 2009, which was sent to numerous permit holders, the SCAQMD stated that it“cannot ensure the long-term validity of permits issued on or after August 3, 2007, or possibly on or afterSeptember 8, 2006” because the issuance of credits from the Priority Reserve may be considered invalid. As aresult, the permits for SCE’s four constructed peaker plants, which were issued in March and April 2007 maybe in jeopardy (see “SCE: Regulatory Matters — Current Regulatory Developments — Peaker PlantGeneration Projects” for further information). However, because the SCAQMD’s appeal of the Superior Courtdecision resulted in the Superior Court’s injunction being stayed, existing permits will remain in effectpending the appeal.

Separately, in August 2008, substantially the same plaintiffs sued the SCAQMD in federal court alleging thatthe emission credits contained in SCAQMD’s New Source Review offset accounts (which include the PriorityReserve) are invalid and seeking to enjoin SCAQMD from transferring them. The SCAQMD has filed amotion to dismiss the federal suit. SCE has joined a coalition of other interested parties that have intervenedin the federal litigation between the SCAQMD and environmental groups.

SCE is in the process of evaluating the impact of the two lawsuits on certain power-purchase agreements thatresulted from its new generation RFO and the potential implications for its long-term resource adequacyrequirements. Separately, EMG is evaluating the potential impact on EME’s Walnut Creek project. See “EMG:Liquidity — Capital Expenditures — Expenditures for New Projects — Walnut Creek Project.”

Water Quality Regulation

Clean Water Act — Prohibition on the Use of Ocean-Based Once-Through Cooling

On March 21, 2008 the California State Water Resources Control Board released its draft scoping documentand preliminary draft Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters forPower Plant Cooling. This state policy is being developed in advance of the issuance of a final rule from theUS EPA on standards for cooling water intake structures at existing large power plants. As anticipated, theScoping Document establishes closed-cycle wet cooling as the best technology available for retrofittingexisting once-through cooled plants like San Onofre. Additionally, the target levels for compliance with the

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state policy correspond to the high end of the ranges originally proposed in the US EPA’s rule. Nuclear-fueledpower plants, including San Onofre, would have until January 1, 2021 to comply with the policy. The policydevelopment schedule included in the scoping document scheduled workshops and the submission of publiccomments in May 2008 and a public hearing in September 2008. The State Board vote has been informallydelayed and is currently anticipated to occur in late 2009. This policy may significantly impact bothoperations at San Onofre and SCE’s ability to procure timely supplies of generating capacity from fossil-fueled plants that use ocean water in once-through cooling systems.

Proposed California Senate Bill

In January 2009, a bill (SB 42) was introduced in the California State Senate which would prohibit powerplants and other industrial facilities from using once-through cooling methods on or after January 1, 2015. Forthe period from January 1, 2011 to December 31, 2014 any power plant or other facility using once-throughcooling methods would be required to pay a seawater fee of $0.15 per 10,000 gallons used. The cost toSan Onofre for the use of seawater for Units 2 and 3 would total approximately $12 million annually. SCEand Edison International oppose this bill because it does not take into account environmental, economic orgrid reliability impacts.

State Water Quality Standards

Illinois

On October 26, 2007, the Illinois EPA filed a proposed rule with the Illinois PCB that would establish morestringent thermal and effluent water quality standards for the Chicago Area Waterway System and Lower DesPlaines River. Midwest Generation’s Fisk, Crawford and Will County stations all use water from the ChicagoArea Waterway System and its Joliet Station uses water from the Lower Des Plaines River for coolingpurposes. The rule, if implemented, is expected to affect the manner in which those stations use water forstation cooling.

The proposed rule is the subject of an administrative proceeding before the Illinois PCB and must be approvedby the Illinois PCB and the Illinois Joint Committee on Administrative Rules. Following state adoption andapproval, the US EPA also must approve the rule. Hearings began on January 28, 2008, and are continuing in2009. Midwest Generation is a party in those proceedings. At this time, it is not possible to predict the timingfor resolution of the proceeding, the final form of the rule, or how it would impact the operation of theaffected stations; however, significant capital expenditures may be required depending on the form of the finalrule.

Pennsylvania Selenium Discharge Order

The discharge from the treatment plant receiving the wastewater stream from EME’s Unit 3 FGD system atthe Homer City facilities has exceeded the stringent water-quality based limits for selenium in the station’sNPDES permit. As a result, EME was notified in April 2002 by the PADEP that it was included in theQuarterly Noncompliance Report submitted to the US EPA. EME Homer City and the PADEP have enteredinto a consent order and agreement related to selenium discharge, which was entered by the Pennsylvania statecourt on July 17, 2007. Under the consent order and agreement, EME Homer City paid a civil penalty of$200,000 and agreed to install modifications to its wastewater system to achieve consistent compliance withdischarge limits. EME Homer City has experienced very few exceedances since entering into the consent orderand agreement.

Environmental Remediation

Edison International is subject to numerous environmental laws and regulations, which require it to incursubstantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove theeffect of past operations on the environment.

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Edison International believes that it is in substantial compliance with environmental regulatory requirements;however, possible future developments, such as the enactment of more stringent environmental laws andregulations, could affect the costs and the manner in which business is conducted and could cause substantialadditional capital expenditures. There is no assurance that additional costs would be recovered from customersor that Edison International’s financial position and results of operations would not be materially affected.

Edison International records its environmental remediation liabilities when site assessments and/or remedialactions are probable and a range of reasonably likely cleanup costs can be estimated. Edison Internationalreviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for eachidentified site using currently available information, including existing technology, presently enacted laws andregulations, experience gained at similar sites, and the probable level of involvement and financial condition ofother potentially responsible parties. These estimates include costs for site investigations, remediation,operations and maintenance, monitoring and site closure. Unless there is a probable amount, EdisonInternational records the lower end of this reasonably likely range of costs (classified as other long-termliabilities) at undiscounted amounts.

As of December 31, 2008, Edison International’s recorded estimated minimum liability to remediate its 45identified sites at SCE (24 sites) and EME (21 sites primarily related to Midwest Generation) was $45 million,$41 million of which was related to SCE including $10 million related to San Onofre. This remediationliability is undiscounted. Edison International’s other subsidiaries have no identified remediation sites. Theultimate costs to clean up Edison International’s identified sites may vary from its recorded liability due tonumerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; thescarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developmentsresulting from investigatory studies; the possibility of identifying additional sites; and the time periods overwhich site remediation is expected to occur. Edison International believes that, due to these uncertainties, it isreasonably possible that cleanup costs could exceed its recorded liability by up to $173 million, all of which isrelated to SCE. The upper limit of this range of costs was estimated using assumptions least favorable toEdison International among a range of reasonably possible outcomes. In addition to its identified sites (sites inwhich the upper end of the range of costs is at least $1 million), SCE also has 30 immaterial sites whose totalliability ranges from $3 million (the recorded minimum liability) to $9 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $29 million ofits recorded liability, through an incentive mechanism (SCE may request to include additional sites). Underthis mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund theremaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties.SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costsincurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $40 million forits estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

Edison International’s identified sites include several sites for which there is a lack of currently availableinformation, including the nature and magnitude of contamination, and the extent, if any, that EdisonInternational may be held responsible for contributing to any costs incurred for remediating these sites. Thus,no reasonable estimate of cleanup costs can be made for these sites.

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of thenext several years are expected to range from $11 million to $31 million. Recorded costs were $29 million,$25 million and $14 million for 2008, 2007 and 2006, respectively.

Based on currently available information, Edison International believes it is unlikely that it will incur amountsin excess of the upper limit of the estimated range for its identified sites and, based upon the CPUC’sregulatory treatment of environmental remediation costs incurred at SCE, Edison International believes thatcosts ultimately recorded will not materially affect its results of operations or financial position. There can beno assurance, however, that future developments, including additional information about existing sites or theidentification of new sites, will not require material revisions to such estimates.

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Tax Positions being Addressed as Part of Active Examinations, Administrative Appeals and the GlobalSettlement

In the normal course, Edison International’s federal income tax returns are examined by the IRS and EdisonInternational challenges deficiency adjustments, asserted as part of an examination, to the AdministrativeAppeals branch of the IRS (IRS Appeals) to the extent Edison International believes its tax reporting positionsproperly complied with the relevant tax law and that the IRS’ basis for making such adjustments lacks merit.Edison International has challenged certain IRS deficiency adjustments, asserted as part of the examination oftax years 1994 – 1999 with IRS Appeals. Edison International has also been under active IRS examination fortax years 2000 – 2002 and during the third quarter of 2008, the IRS commenced an examination of tax years2003 – 2006. In addition, the statute of limitations remains open for tax years 1986 – 1993, which has allowedEdison International to file certain affirmative claims related to these tax years.

Most of the tax positions that Edison International is addressing with IRS Appeals relate to the timing of whendeductions for federal income tax purposes are allowed to be reflected on filed income tax returns and, assuch, any deductions not sustained would be deductible on future tax returns filed by Edison International.However, any penalties and interest associated with disallowed deductions would result in a permanent cost.Edison International has also filed affirmative claims with respect to certain tax years 1986 through 2005 withthe IRS and state tax authorities. At this time, there has not been a final determination of these affirmativeclaims by the IRS or state tax authorities. Benefits, if any, associated with these affirmative claims would berecorded in accordance with FIN 48 which provides that recognition would occur at the earlier of whenEdison International would make an assessment that the affirmative claim position has a more likely than notprobability of being sustained or when a settlement of the affirmative claim is consummated with the taxauthority. Certain of these affirmative claims have been recognized as part of the implementation of FIN 48.

Edison International has been engaged in settlement negotiations with the IRS to reach a Global Settlementdescribed below of all unresolved tax disputes and affirmative claims for tax years 1986 – 2002 and to resolvecross-border, leveraged-lease issues in their entirety.

In addition to the IRS audits, Edison International’s California and other state income tax returns are, in thenormal course, subjected to examination by the California Franchise Tax Board and the other state taxauthorities. The Franchise Tax Board has substantially completed its examination of all tax years through 2002and is currently awaiting resolution of the IRS audit before finalizing the audit for these tax years. EdisonInternational is currently under active examination for tax years 2003 – 2004 and remains subject toexamination by the California Franchise Tax Board for tax years 2005 and forward.

Edison International filed amended California Franchise tax returns for tax years 1997 – 2002 to mitigate thepossible imposition of California non-economic substance penalty provisions on transactions that may beconsidered as Listed or substantially similar to Listed Transactions described in an IRS notice that waspublished in 2001. These transactions include certain Edison Capital leveraged-lease transactions and an SCEsubsidiary contingent liability company transaction, described below. Edison International filed these amendedreturns under protest retaining its appeal rights.

The issues discussed below are included in the ongoing IRS examination and appeals process and are includedin the scope of issues being addressed as part of the Global Settlement process.

Balancing Account Over-Collections

In response to an affirmative claim filed by Edison International related to balancing account over-collections,the IRS issued a Notice of Proposed Adjustment in July 2007 as part of the ongoing IRS examinations andadministrative appeals processes. The tax years to which adjustments are made pursuant to this Notice ofProposed Adjustment are included in the scope of the Global Settlement process. The cash and earningsimpacts of this position are dependent on the ultimate settlement of all open tax issues, including this issue, in

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these tax years. Edison International expects that resolution of this issue could potentially increase earningsand cash flows within the range of $70 million to $80 million and $300 million to $350 million, respectively.

Contingent Liability Company

The IRS has asserted tax deficiencies and penalties of $53 million and $22 million, respectively, for tax years1997 – 1999 with respect to a transaction entered into by a former SCE subsidiary which the IRS has assertedto be substantially similar to a Listed Transaction described by the IRS as a contingent liability company.

Cross-Border Lease Transactions

As part of a nationwide challenge of cross border lease transactions, the IRS has asserted deficiencies relatedto Edison International’s deferral of income taxes associated with certain of its cross-border, leveraged leases.

These asserted deficiencies relate to Edison Capital’s income tax treatment of both its foreign power plant andelectric locomotive sale/leaseback transactions entered into in 1993 and 1994 (Replacement Leases, which theIRS refers to as sale-in/lease-out or SILOs) and its foreign power plants and electric transmission systemlease/leaseback transactions entered into in 1997 and 1998 (Lease/Leaseback, which the IRS refers to as lease-in/lease-out or LILOs). For tax years 1994 – 1999, Edison International is challenging the asserted deficienciesin ongoing IRS appeals proceedings and is seeking to resolve the asserted deficiencies as part of the GlobalSettlement process.

In 1999, Edison Capital entered into a lease/service contract transaction involving a foreign telecommunicationsystem (Service Contract, which the IRS refers to as a SILO). As part of an ongoing examination of 2000 –2002, the IRS examination branch has been reviewing Edison International’s income tax treatment of thisService Contract. The income tax treatment of the Service Contract is included in the Global Settlementprocess for all tax years.

The following table summarizes estimated federal and state income taxes deferred from these leases as ofDecember 31, 2008. Repayment of the entire amount of the deferred income taxes, as provided in the tablebelow, would be accelerated if Edison International and the IRS were unable to reach a settlement and the IRSposition were sustained in litigation:

In millions

Tax YearsUnder Appeal1994 – 1999

Tax YearsUnder Audit2000 – 2006

UnauditedTax Years

2007 – 2008 Total

Replacement Leases (SILO) $ 44 $ 42 $ 7 $ 93Lease/Leaseback (LILO) 563 572 (32) 1,103Service Contract (SILO) — 326 110 436

Total $ 607 $ 940 $ 85 $ 1,632

As of December 31, 2008, the after-tax interest on the proposed tax adjustments is estimated to beapproximately $643 million. The IRS has also asserted a 20% penalty on any sustained adjustment (other thanwith respect to the Service Contract).

Edison International believes that its maximum earnings exposure related to these leases, measured as ofDecember 31, 2008, is approximately $1.3 billion after taxes, calculated by reclassifying deferred incometaxes to current, re-computing the cumulative earnings under the leases in accordance with lease accountingrules (FASB Staff Position FAS 13-2), and recording interest related to the current income tax liability. Interestwill continue to accrue until the alleged deficiency is resolved. This exposure does not include IRS assertedpenalties of 20%, as Edison International does not believe that even if the tax return positions taken by EdisonCapital are successfully challenged by the IRS that these penalties would be sustained. The current and futureearnings and cash positions of SCE and EME are virtually unaffected by these leases.

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During the second quarter of 2008, there were court decisions involving income taxation of cross-borderleveraged leases that were adverse to the taxpayers involved. These developments underscore the uncertainnature of tax conclusions in this area. Despite these developments, Edison International believes it properlyreported these transactions based on applicable statutes, regulations and case law and, in the absence of anysettlement with the IRS, will continue to vigorously defend its tax treatment of these leases. EdisonInternational will continue to monitor and evaluate its lease transactions with respect to future events. Futureadverse developments, including further adverse case law developments, could change Edison International’scurrent conclusions.

Global Settlement

As previously disclosed, Edison International has negotiated the material terms of a Global Settlement withthe IRS which, if consummated, would resolve cross-border, leveraged lease issues in their entirety and allother outstanding tax disputes for open tax years 1986 through 2002, including certain affirmative claims forunrecognized tax benefits. See “Edison International Notes to Consolidated Financial Statements — Note 4.Income Taxes.” Consummation of the Global Settlement is subject to review by the Staff of the JointCommittee on Taxation, a committee of the United States Congress (the “Joint Committee”). The IRSsubmitted the pertinent terms of the Global Settlement to the Joint Committee during the fourth quarter of2008, and its response is currently pending. Edison International cannot predict the timing of when the JointCommittee will complete its review. Moreover, Edison International cannot predict whether the JointCommittee will concur with the settlement terms negotiated by the IRS for the Global Settlement issues andwhether any non-concurrence would result in the IRS proposing different settlement terms. Failure toconsummate the Global Settlement and to be successful in any ensuing litigation over issues included in theGlobal Settlement process, including asserted deficiencies regarding the cross-border leases, could have anadverse affect on Edison International.

In the first quarter of 2009, Edison International terminated two of the six cross-border leveraged leases. Thetiming for terminating the remaining cross-border leases is uncertain and could occur prior to the JointCommittee completing its work or otherwise prior to consummation of the settlement. Edison Capital and itssubsidiaries have reached an agreement based on executed term sheets with all of the counterparties to itsSILOs and LILOs which contemplate termination of the leases subject to a final settlement agreement with theIRS. Certain of these agreements are not binding on Edison Capital or the counterparties until suchtermination. Upon termination of the leases, the lessees would be required to make termination payments fromcertain collateral deposits associated with the leases, and Edison International would no longer recognizeearnings from such leases. In 2008 income from leveraged leases was $28 million. If all settlements includedin the Global Settlement process were ultimately concluded consistent with the terms submitted to the JointCommittee, Edison International would expect that the settlement of the disputed lease issues and theresolution of the above-mentioned affirmative claims would result in a portion of any charge initially recordedupon termination of the leases being offset and/or reduced, and the net after-tax earnings charge that wouldremain is currently expected to be less than half of the maximum after-tax earnings exposure, calculated as ofDecember 31, 2008, discussed above. Furthermore, if all settlements included in the Global Settlementdiscussions were ultimately concluded consistent with the terms submitted to the Joint Committee, the netcash impact upon Edison International as a whole of the Global Settlement and lease terminations would bepositive over time. Termination of the leases prior to consummation of the settlements would result in EdisonInternational initially recording an after-tax charge to earnings currently estimated to be at least $650 million(and potentially up to the maximum earnings exposure indicated above), which would be reduced and/or offsetupon completion of the Global Settlement.

To the extent that Edison International is unable to consummate the Global Settlement or other acceptablesettlement with the IRS, Edison International will continue to vigorously defend its tax treatment of the leasesand is prepared to take legal action. If Edison International were to commence litigation in certain forums, itwould need to make payments of the disputed taxes, along with interest and any penalties asserted by the IRS,

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and thereafter pursue refunds. In the United States Tax Court, no upfront payment would be required. In 2006,Edison International paid $111 million of the taxes, interest and penalties for tax year 1999 followed by arefund claim for the same amount. The IRS did not act on this refund claim within the statutory period, whichprovides Edison International with the option of being able to take legal action to assert its refund claim. Tothe extent an acceptable settlement is not reached with the IRS, Edison International, based on its preferencefor litigation forum, may file refund claims for any taxes, interest and penalties paid for tax years related tothese leases. However, Edison International has not decided whether and to what extent it would makeadditional payments related to later tax years to fund its right to litigate in certain forums should the GlobalSettlement, or another settlement, not be consummated.

If and when Edison International and the IRS consummate a settlement, Edison International will file amendedtax returns with the Franchise Tax Board and other state administrative agencies, for those states in whichEdison International has an income tax filing requirement, to reflect the respective state income tax impact ofthe settlement terms.

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Management’s Responsibility for Financial Reporting

The management of Edison International is responsible for the integrity and objectivity of the accompanyingfinancial statements and related information. The statements have been prepared in accordance withaccounting principles generally accepted in the United States of America and are based, in part, onmanagement estimates and judgment. Management believes that the financial statements fairly reflect EdisonInternational’s financial position and results of operations.

As a further measure to assure the ongoing objectivity and integrity of financial information, the AuditCommittee of the Board of Directors, which is composed of independent directors, meets periodically, bothjointly and separately, with management, the independent auditors and internal auditors, who have unrestrictedaccess to the Committee. The Committee annually appoints a firm of independent auditors to conduct an auditof Edison International’s financial statements and internal control over financial reporting; reviews accounting,internal control, auditing and financial reporting issues; and is advised of management’s actions regardingfinancial reporting and internal control matters.

Edison International and its subsidiaries maintain high standards in selecting, training and developingpersonnel to assure that its operations are conducted in conformity with applicable laws and are committed tomaintaining the highest standards of personal and corporate conduct. Management maintains programs toencourage and assess compliance with these standards.

Edison International’s independent registered public accounting firm, PricewaterhouseCoopers LLP, areengaged to audit the financial statements included in this Annual Report in accordance with the standards ofthe Public Company Accounting Oversight Board (United States) and has issued an attestation report onEdison International’s internal controls over financial reporting, as stated in their report which is included inthis Annual Report on the following page.

Management’s Report on Internal Control over Financial Reporting

Edison International’s management is responsible for establishing and maintaining adequate internal controlover financial reporting (as that term is defined in Rule 13a-15(f) under the Exchange Act). Under thesupervision and with the participation of its Chief Executive Officer and Chief Financial Officer, EdisonInternational’s management conducted an evaluation of the effectiveness of internal control over financialreporting based on the framework set forth in Internal Control — Integrated Framework issued by theCommittee of Sponsoring Organizations of the Treadway Commission (COSO). Based on its evaluation underthe COSO framework, Edison International’s management concluded that internal control over financialreporting was effective as of December 31, 2008. Edison International’s internal control over financialreporting as of December 31, 2008 has been audited by PricewaterhouseCoopers LLP, an independentregistered public accounting firm, as stated in their report on the financial statements in Edison International’s2008 Annual Report to shareholders, which is incorporated herein by this reference.

Disclosure Controls and Procedures

The certifications of the Chief Executive Officer and Chief Financial Officer that are required by Section 302of the Sarbanes-Oxley Act of 2002 are included as exhibits to Edison International’s annual report onForm 10-K. In addition, in 2008, Edison International’s Chief Executive Officer provided to the New YorkStock Exchange (NYSE) the Annual CEO Certification regarding Edison International’s compliance with theNYSE’s corporate governance standards.

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Report of Independent Registered Public Accounting Firm Edison International

To the Board of Directors and Shareholders of Edison International

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements ofincome, comprehensive income, shareholders’ equity, and cash flows present fairly, in all material respects, thefinancial position of Edison International (the “Company”) and its subsidiaries at December 31, 2008 and2007, and the results of their operations and their cash flows for each of the three years in the period endedDecember 31, 2008 in conformity with accounting principles generally accepted in the United States ofAmerica. Also in our opinion, the Company maintained, in all material respects, effective internal control overfinancial reporting as of December 31, 2008, based on criteria established in Internal Control — IntegratedFramework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). TheCompany’s management is responsible for these financial statements, for maintaining effective internal controlover financial reporting and for its assessment of the effectiveness of internal control over financial reporting,included in the accompanying Management’s Report on Internal Control over Financial Reporting. Ourresponsibility is to express opinions on these financial statements and on the Company’s internal control overfinancial reporting based on our integrated audits. We conducted our audits in accordance with the standardsof the Public Company Accounting Oversight Board (United States). Those standards require that we plan andperform the audits to obtain reasonable assurance about whether the financial statements are free of materialmisstatement and whether effective internal control over financial reporting was maintained in all materialrespects. Our audits of the financial statements included examining, on a test basis, evidence supporting theamounts and disclosures in the financial statements, assessing the accounting principles used and significantestimates made by management, and evaluating the overall financial statement presentation. Our audit ofinternal control over financial reporting included obtaining an understanding of internal control over financialreporting, assessing the risk that a material weakness exists, and testing and evaluating the design andoperating effectiveness of internal control based on the assessed risk. Our audits also included performing suchother procedures as we considered necessary in the circumstances. We believe that our audits provide areasonable basis for our opinions.

As discussed in Notes 1, 4, 5 and 10 to the consolidated financial statements, the Company changed themanner in which it accounts for stock-based compensation as of January 1, 2006, defined benefit pension andother post retirement plans as of December 31, 2006, uncertain tax positions as of January 1, 2007, andmargin and cash collateral deposits related to derivative positions and fair value measurement and disclosureaccounting principles as of January 1, 2008.

A company’s internal control over financial reporting is a process designed to provide reasonable assuranceregarding the reliability of financial reporting and the preparation of financial statements for external purposesin accordance with generally accepted accounting principles. A company’s internal control over financialreporting includes those policies and procedures that (i) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company;(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accounting principles, and that receipts and expenditures ofthe company are being made only in accordance with authorizations of management and directors of thecompany; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company’s assets that could have a material effect on the financialstatements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detectmisstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk thatcontrols may become inadequate because of changes in conditions, or that the degree of compliance with thepolicies or procedures may deteriorate.

Los Angeles, CaliforniaMarch 2, 2009

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Consolidated Statements of Income Edison International

In millions, except per-share amounts Year ended December 31, 2008 2007 2006

Electric utility $ 11,246 $ 10,231 $ 9,859Nonutility power generation 2,808 2,575 2,228Financial services and other 58 62 82

Total operating revenue 14,112 12,868 12,169

Fuel 2,147 1,875 1,757Purchased power 3,845 3,235 3,099Other operation and maintenance 4,288 4,065 3,721Depreciation, decommissioning and amortization 1,313 1,181 1,105Contract buyout/termination and other (44) 3 (2)


Operating income 2,563 2,509 2,489Interest and dividend income 62 154 169Equity in income from partnerships and unconsolidated subsidiaries – net 31 79 79Other nonoperating income 113 95 133Interest expense – net of amounts capitalized (700) (752) (806)Other nonoperating deductions (125) (45) (63)Loss on early extinguishment of debt — (241) (146)

Income from continuing operations before tax and minority interest 1,944 1,799 1,855Income tax expense 596 492 582Dividends on preferred and preference stock of utility not subject to

mandatory redemption 51 51 51Minority interest 82 156 139

Income from continuing operations 1,215 1,100 1,083Income (loss) from discontinued operations – net of tax — (2) 97

Income before accounting change 1,215 1,098 1,180Cumulative effect of accounting change – net of tax — — 1

Net income $ 1,215 $ 1,098 $ 1,181

Weighted-average shares of common stock outstanding 326 326 326Basic earnings (loss) per share:Continuing operations $ 3.69 $ 3.34 $ 3.28Discontinued operations — (0.01) 0.30

Total $ 3.69 $ 3.33 $ 3.58

Weighted-average shares, including effect of dilutive securities 329 331 330Diluted earnings (loss) per share:Continuing operations $ 3.68 $ 3.32 $ 3.27Discontinued operations — (0.01) 0.30

Total $ 3.68 $ 3.31 $ 3.57

Dividends declared per common share $ 1.225 $ 1.175 $ 1.10

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Comprehensive Income Edison International

In millions Year ended December 31, 2008 2007 2006

Net income $ 1,215 $ 1,098 $ 1,181Other comprehensive income (loss), net of tax:

Foreign currency translation adjustments – net of income tax benefit of$2, $1 and $1 for 2008, 2007 and 2006, respectively (3) (2) (1)

Pension and postretirement benefits other than pensions:Net loss arising during period – net of income tax benefit of $23 and

$1 for 2008 and 2007, respectively (36) (2) —Amortization of net loss included in expense – net of income tax

expense of $3 for 2007 — 5 —Prior service cost arising during the period – net (1) — —Amortization of prior service included in expense – net (1) (1) —

Minimum pension liability adjustment — — (1)Unrealized gains (losses) on cash flow hedges:

Unrealized gains (losses) arising during the period – net of income taxexpense (benefit) of $138, $(160) and $214 for 2008, 2007 and 2006,respectively 211 (234) 314

Reclassification adjustment for gains (losses) included in net income –net of income tax expense of $58, $45 and $9 for 2008, 2007 and2006, respectively 89 64 12

Other comprehensive income (loss) 259 (170) 324

Comprehensive income $ 1,474 $ 928 $ 1,505


119

Consolidated Balance Sheets Edison International


ASSETSCash and equivalents $ 3,916 $ 1,441Short-term investments 7 81Receivables, less allowances of $39 and $34 for uncollectible accounts at respective

dates 1,006 1,033Accrued unbilled revenue 328 370Fuel inventory 163 116Materials and supplies 390 316Derivative assets 327 109Restricted cash 3 3Margin and collateral deposits 105 121Regulatory assets 605 197Accumulated deferred income taxes – net 104 167Other current assets 399 290

Total current assets 7,353 4,244

Nonutility property – less accumulated provision for depreciation of $2,019 and$1,765 at respective dates 5,374 4,906

Nuclear decommissioning trusts 2,524 3,378Investments in partnerships and unconsolidated subsidiaries 229 272Investments in leveraged leases 2,467 2,473Other investments 89 96

Total investments and other assets 10,683 11,125

Utility plant, at original cost:Transmission and distribution 20,006 18,940Generation 1,819 1,767

Accumulated provision for depreciation (5,570) (5,174)Construction work in progress 2,454 1,693Nuclear fuel, at amortized cost 260 177

Total utility plant 18,969 17,403

Derivative assets 244 122Restricted cash 43 48Rent payments in excess of levelized rent expense under plant operating leases 878 716Regulatory assets 5,414 2,721Other long-term assets 1,031 1,144

Total long-term assets 7,610 4,751

Total assets $ 44,615 $ 37,523


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In millions, except share amounts December 31, 2008 2007

LIABILITIES AND SHAREHOLDERS’ EQUITYShort-term debt $ 2,143 $ 500Long-term debt due within one year 174 18Accounts payable 1,031 979Accrued taxes 590 49Accrued interest 187 160Counterparty collateral 8 42Customer deposits 228 219Book overdrafts 224 212Derivative liabilities 178 125Regulatory liabilities 1,111 1,019Other current liabilities 823 933

Total current liabilities 6,697 4,256

Long-term debt 10,950 9,016

Accumulated deferred income taxes – net 5,717 5,196Accumulated deferred investment tax credits 109 114Customer advances 137 155Derivative liabilities 776 101Accumulated provision for pensions and benefits 2,860 1,089Asset retirement obligations 3,042 2,892Regulatory liabilities 2,481 3,433Other deferred credits and other long-term liabilities 1,137 1,617

Total deferred credits and other liabilities 16,259 14,597

Total liabilities 33,906 27,869

Commitments and contingencies (Note 6)Minority interest 285 295

Preferred and preference stock of utility not subject to mandatory redemption 907 915

Common stock, no par value (325,811,206 shares outstanding at each date) 2,272 2,225Accumulated other comprehensive income (loss) 167 (92)Retained earnings 7,078 6,311

Total common shareholders’ equity 9,517 8,444

Total liabilities and shareholders’ equity $ 44,615 $ 37,523

Authorized common stock is 800 million shares at each reporting period


121

Consolidated Balance Sheets Edison International

Consolidated Statements of Cash Flows Edison International

In millions Year ended December 31, 2008 2007 2006Cash flows from operating activities:Net income $ 1,215 $ 1,098 $ 1,181Less: income (loss) from discontinued operations — (2) 97

Income from continuing operations 1,215 1,100 1,084

Adjustments to reconcile to net cash provided by operating activities:Cumulative effect of accounting change – net of tax — — (1)Depreciation, decommissioning and amortization 1,313 1,181 1,105Net earnings is nuclear ARO regulatory assets and liabilities (10) 143 130Other amortization 106 111 99Contract buyout/termination and other (44) 3 (2)Stock-based compensation 34 37 47Minority interest 82 156 139Deferred income taxes and investment tax credits 207 (39) (136)Equity in income from partnerships and unconsolidated subsidiaries-net (31) (75) (76)Income from leveraged leases (51) (49) (67)Regulatory assets (2,725) 503 74Regulatory liabilities (221) 176 336Loss on early extinguishment of debt — 241 146Levelized rent expense (162) (160) (161)Derivative assets 41 (9) 260Derivative liabilities 808 (184) 285Other assets 224 (180) (231)Other liabilities 1,344 195 309Margin and collateral deposits – net of collateral received (19) 75 193Receivables and accrued unbilled revenue 170 (59) 208Inventory and other current assets (204) (121) (68)Book overdrafts 16 72 —Accrued interest and taxes 367 12 (123)Accounts payable and other current liabilities (242) 33 (137)Distributions and dividends from unconsolidated entities (8) 33 61

Operating cash flows from discontinued operations — (2) 94

Net cash provided by operating activities 2,210 3,193 3,568

Cash flows from financing activities:Long-term debt issued 2,632 2,930 2,350Premiums paid on extinguishment of debt and long-term debt issuance costs (21) (241) (181)Long-term debt repaid (295) (3,215) (2,110)Bonds repurchased (212) (37) —Issuance of preference stock — — 196Preferred stock redeemed (7) — —Rate reduction notes repaid — (246) (246)Book overdrafts — — (118)Short-term debt financing – net 1,643 500 —Contribution from minority shareholders 12 — —Shares purchased for stock-based compensation (66) (215) (173)Proceeds from stock option exercises 30 86 66Excess tax benefits related to stock-based awards 10 45 27Dividends to minority shareholders (119) (106) (162)Dividends paid (397) (378) (352)

Net cash provided (used) by financing activities $ 3,210 $ (877) $ (703)


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Cash flows from investing activities:Capital expenditures $ (2,824) $ (2,826) $ (2,536)Purchase of interest of acquired companies (19) (33) (18)Proceeds from sale of property and interest in projects 113 2 89Proceeds from nuclear decommissioning trust sales 3,130 3,697 3,010Purchases of nuclear decommissioning trusts investments and other (3,137) (3,830) (3,150)Proceeds from partnerships and unconsolidated subsidiaries, net of

investment 65 42 25Maturities and sales of short-term investments 96 9,953 7,128Purchases of short-term investments (22) (9,476) (7,474)Restricted cash 4 99 13Customer advances for construction and other investments (351) (298) (50)

Net cash used by investing activities (2,945) (2,670) (2,963)

Net increase (decrease) in cash and equivalents 2,475 (354) (98)Cash and equivalents, beginning of year 1,441 1,795 1,893

Cash and equivalents – end of year $ 3,916 $ 1,441 $ 1,795


123

Consolidated Statements of Cash Flows Edison International

Consolidated Statements of Changes in Common Shareholders’ Equity Edison International

In millionsCommon

Stock

AccumulatedOther

ComprehensiveIncome (Loss)

RetainedEarnings

TotalCommon

Shareholders’Equity

Balance at December 31, 2005 $ 2,043 $ (226) $ 4,798 $ 6,615

Net income 1,181 1,181Other comprehensive income 324 324SFAS No. 158 – Pension and other

postretirement benefits (30) (30)Tax effect 10 10

Common stock dividends declared ($1.10 pershare) (358) (358)

Shares purchased for stock-basedcompensation (33) (136) (169)

Proceeds from stock option exercises 66 66Noncash stock-based compensation and other 42 42Excess tax benefits related to stock-based

awards 28 28

Balance at December 31, 2006 $ 2,080 $ 78 $ 5,551 $ 7,709

Net income 1,098 1,098FIN 48 adoption 250 250Other comprehensive loss (170) (170)Common stock dividends declared ($1.175

per share) (383) (383)Shares purchased for stock-based

compensation (216) (216)Proceeds from stock option exercises 86 86Noncash stock-based compensation and other 32 (7) 25Excess tax benefits related to stock-based

awards 45 45Change in classification of shares purchased

to settle performance shares 68 (68) —

Balance at December 31, 2007 $ 2,225 $ (92) $ 6,311 $ 8,444

Net income 1,215 1,215Other comprehensive income 259 259Common stock dividends declared ($1.225

per share) (399) (399)Gain on reacquired preferred stock 2 2Shares purchased for stock-based

compensation (66) (66)Proceeds from stock option exercises 30 30Noncash stock-based compensation and other 35 (13) 22Excess tax benefits related to stock-based

awards 10 10

Balance at December 31, 2008 $ 2,272 $ 167 $ 7,078 $ 9,517

Authorized common stock is 800 million shares. Outstanding common stock is 325,811,206 shares for allyears presented.


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Note 1. Summary of Significant Accounting Policies

Edison International’s principal wholly owned subsidiaries include: SCE, a rate-regulated electric utility thatsupplies electric energy to a 50,000 square-mile area of central, coastal and southern California; and EMG, awholly owned non-utility subsidiary; EMG is the holding company of EME and Edison Capital. EME is anindependent power producer engaged in the business of developing, acquiring, owning or leasing, operatingand selling energy and capacity from independent power production facilities; EME also conducts hedging andenergy trading activities in power markets open to competition. Edison Capital is a provider of capital andfinancial services. EME has domestic projects and one foreign project in Turkey; Edison Capital has domesticand foreign investments, primarily in Europe, Australia and Africa.

Basis of Presentation

The consolidated financial statements include Edison International and its wholly owned subsidiaries. EdisonInternational consolidates subsidiaries in which it has a controlling interest and VIEs in which they are theprimary beneficiary. In addition, Edison International generally uses the equity method to account forsignificant interests in (1) partnerships and subsidiaries in which it owns a significant or less than controllinginterest and (2) VIEs in which it is not the primary beneficiary. Intercompany transactions have beeneliminated, except EME’s profits from energy sales to SCE, which are allowed in utility rates.

SCE’s accounting policies conform to accounting principles generally accepted in the United States ofAmerica, including the accounting principles for rate-regulated enterprises, which reflect the rate-makingpolicies of the CPUC and the FERC. SCE applies SFAS No. 71 to the portion of its operations in whichregulators set rates at levels intended to recover the estimated costs of providing service, plus a return oncapital. Due to timing and other differences in the collection of electric utility revenue, these principles allowan incurred cost that would otherwise be charged to expense by a nonregulated entity to be capitalized as aregulatory asset if it is probable that the cost is recoverable through future rates; and conversely theseprinciples require creation of a regulatory liability for probable future costs collected through rates in advanceof the actual costs being incurred. SCE’ management continually evaluates the anticipated recovery ofregulatory assets, liabilities, and electric utility revenue subject to refund and provides for allowances and/orreserves as appropriate.

Certain prior-year reclassifications have been made to conform to the December 31, 2008 consolidatedfinancial statement presentation mostly pertaining to the adoption of FIN 39-1 and the elimination of thepreviously reported income statement caption “Provision for regulatory adjustment clauses — net” throughclassifications within relevant captions including “Operating revenue,” “Purchased power,” “Other operationand maintenance” and “Depreciation, decommissioning and amortization.”

Financial statements prepared in conformity with accounting principles generally accepted in the United Statesof America require management to make estimates and assumptions that affect the reported amounts of assetsand liabilities and disclosure of contingency assets and liabilities at the date of the financial statements and thereported amounts of revenue and expenses during the reported period. Actual results could differ from thoseestimates.

Book Overdrafts

Book overdrafts represent timing difference associated with outstanding checks in excess of cash funds thatare on deposit with financial institutions. SCE’s ending daily cash funds are temporarily invested in short-terminvestments, until required for check clearings. SCE reclassifies the amount for checks issued but not yet paidby the financial institution, from cash to book overdrafts.

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Cash and Equivalents

Cash and cash equivalents as of December 31, 2008 and 2007 consisted of the following:


2008December 31,

2007

Cash $ 178 $ 295

Money market funds $ 3,543 $ 633U.S. Treasury securities — 47U.S. government agency securities 164 —Commercial paper 30 316Time deposits (certificates of deposit) 1 150

Total cash equivalents $ 3,738 $ 1,146

Total cash and cash equivalents $ 3,916 $ 1,441

Cash equivalents, with the exception of money market funds, were stated at amortized cost plus accruedinterest. The carrying value of cash equivalents approximates fair value due to maturities of less than threemonths. For further discussion of money market funds, see Note 10. Additionally, cash and equivalents of$89 million and $110 million at December 31, 2008 and 2007, respectively, are included for four projects thatEdison International is consolidating under an accounting interpretation for VIEs. For a discussion of restrictedcash, see “Restricted Cash.”

Deferred Financing Costs

Debt premium, discount and issuance expenses are deferred and amortized (on a straight-line basis for SCEand on a basis which approximates the effective interest rate method for EMG) through interest expense overthe life of each related issue. Under CPUC rate-making procedures, debt reacquisition expenses are amortizedover the remaining life of the reacquired debt or, if refinanced, the life of the new debt. California lawprohibits SCE from incurring or guaranteeing debt for its nonutility affiliates. SCE had unamortized loss onreacquired debt of $309 million at December 31, 2008 and $331 million at December 31, 2007 reflected in“Regulatory assets” in the long-term section of the consolidated balance sheets. Edison International hadunamortized debt issuance costs of $86 million at December 31, 2008 and $83 million at December 31, 2007reflected in “Other long-term assets” on the consolidated balance sheets.

Derivative Instruments and Hedging Activities

Edison International uses derivative financial instruments to manage financial exposure on its investments andfluctuations in commodity prices, interest rates, foreign currency exchange rates, and emission andtransmission rights. Edison International manages these risks in part by entering into interest rate swap, capand lock agreements, and forward commodity transactions, including options, swaps and futures. EdisonInternational has a power marketing and trading subsidiary that markets the energy and capacity of EME’smerchant generating fleet and, in addition, trades electric power and energy and related commodity andfinancial products.

Edison International is exposed to credit loss in the event of nonperformance by counterparties. To mitigatecredit risk from counterparties, master netting agreements are used whenever possible and counterparties maybe required to pledge collateral depending on the creditworthiness of each counterparty and the risk associatedwith the transaction.

Edison International records its derivative instruments on its consolidated balance sheets at fair value as eitherassets or liabilities unless they meet the definition of a normal purchase or sale. The normal purchases andsales exception requires, among other things, physical delivery in quantities expected to be used or sold over areasonable period in the normal course of business. All changes in the fair value of derivatives are recognized

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Notes to Consolidated Financial Statements

currently in earnings unless specific hedge criteria are met which requires Edison International to formallydocument, designate, and assess the effectiveness of hedge transactions. For those derivative transactions thatqualify for and for which Edison International has elected hedge accounting, gains or losses from changes inthe fair value of a recognized asset or liability or a firm commitment are reflected in earnings for theineffective portion of a designated fair value hedge. For a designated hedge of the cash flows of a forecastedtransaction or a foreign currency exposure, the effective portion of the gain or loss is initially recorded as aseparate component of shareholders’ equity under the caption “Accumulated other comprehensive income(loss),” and subsequently reclassified into earnings when the forecasted transaction affects earnings. Theremaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.

Derivative assets and liabilities are shown at gross amounts on the consolidated balance sheets, except that netpresentation is used when Edison International has the legal right of offset, such as multiple contracts executedwith the same counterparty under master netting arrangements. In addition, derivative positions are offsetagainst margin and cash collateral deposits in accordance with FIN No. 39-1 as discussed below in “Marginand Collateral Deposits” and “New Accounting Pronouncements.” The results of derivative activities arerecorded as part of cash flows from operating activities on the consolidated statements of cash flows.

To mitigate SCE’s exposure to spot-market prices, the CPUC has authorized SCE to enter into power purchasecontracts (including QFs), energy options, tolling arrangements and forward physical contracts. SCE recordsthese derivative instruments on its consolidated balance sheets at fair value unless they meet the definition of anormal purchase or sale (as discussed above), or are classified as VIEs or leases. The derivative instrumentfair values are marked to market at each reporting period. Any fair value changes are expected to be recoveredfrom or refunded to customers through regulatory mechanisms and therefore SCE’s fair value changes have noimpact on purchased-power expense or earnings. As a result, fair value changes do not affect SCE’s earnings.SCE has elected not to use hedge accounting for these transactions due to this regulatory accountingtreatment.

Most of SCE’s QF contracts are not required to be recorded on the consolidated balance sheets because theyeither do not meet the definition of a derivative or meet the normal purchases and sales exception. However,SCE purchases power from certain QFs in which the contract pricing is based on a natural gas index, but thepower is not generated with natural gas. The portion of these contracts that is not eligible for the normalpurchases and sales exception is recorded on the consolidated balance sheets at fair value. Unit-specificcontracts (signed or modified after June 30, 2003) in which SCE takes virtually all of the output of a facilityare generally considered to be leases under EITF No. 01-8.

SCE enters into interest-rate locks to mitigate interest rate risk associated with future financings. SCE expectsto recover any fair value changes associated with the interest-rate locks through regulatory mechanisms.Realized and unrealized gains and losses do not affect current earnings. Realized gains/losses are amortizedand recovered through interest expense over the life of the new debt.

EME’s risk management and trading operations are conducted by a subsidiary. As a result of a number ofindustry and credit-related factors, the subsidiary has minimized its price risk management and tradingactivities not related to EME’s power plants or investments in energy projects. To the extent it engages intrading activities, EME’s trading subsidiary seeks to manage price risk and to create stability of future incomeby selling electricity in the forward markets and, to a lesser degree, to generate profit from price volatility ofelectricity and fuels by buying and selling these commodities in wholesale markets. EME generally balancesforward sales and purchase contracts and manages its exposure through a value at risk analysis for tradingpositions and gross margin at risk analysis for hedge positions. Financial instruments that are utilized fortrading purposes are measured at fair value and are included in the consolidated balance sheets as derivativeassets or liabilities. In the absence of quoted market prices, financial instruments are valued at fair value,considering time value, volatility of the underlying commodity, and other factors as determined by EME. Fairvalue changes for EME’s trading operations are reflected in nonutility power generation revenues. Derivativeassets include the fair value of open financial positions related to trading activities and the present value of net

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amounts receivable from structured transactions. Derivative liabilities include the fair value of open financialpositions related to trading activities.

EME has nontrading derivative financial instruments arising from energy contracts related to the Illinois plantsand Homer City. In assessing the fair value of its nontrading derivative financial instruments, EME uses avariety of methods and assumptions based on the market conditions and associated risks existing at eachbalance sheet date. The fair value of the commodity price contracts takes into account quoted market prices,time value of money, volatility of the underlying commodities and other factors. EME’s unrealized gains andlosses from its energy contracts are classified as part of nonutility power generation revenue.

See further information about Edison International derivative instruments in Notes 2, 7 and 10.

Dividend Restrictions

The CPUC regulates SCE’s capital structure and limits the dividends it may pay Edison International. InSCE’s most recent cost of capital proceeding, the CPUC sets an authorized capital structure for SCE whichincluded a common equity component of 48%. SCE may make distributions to Edison International as long asthe common equity component of SCE’s capital structure remains at or above the authorized level on a13-month weighted average basis of 48%. At December 31, 2008, SCE’s 13-month weighted-average commonequity component of total capitalization was 50.6% resulting in the capacity to pay $345 million in additionaldividends.

Earnings Per Share

Edison International computes EPS using the two-class method, which is an earnings allocation formula thatdetermines EPS for each class of common stock and participating security. Edison International’s participatingsecurities are stock based compensation awards payable in common shares, including stock options,performance shares and restricted stock units, which earn dividend equivalents on an equal basis with commonshares. Stock options awarded during the period 2003 through 2006 received dividend equivalents. Stockoptions awarded prior to 2002 and after 2006 were granted without a dividend equivalent feature. As a resultof meeting a performance trigger, the options granted in 1998 and 1999 began earning dividend equivalents in2006. Performance shares awarded in 2005 – 2008 received dividend equivalents. EPS was computed asfollows:


Basic earnings per share – continuing operations:Income from continuing operations $ 1,215 $ 1,100 $ 1,083Gain on redemption of preferred stock 2 — —Participating securities dividends (14) (12) (14)

Income from continuing operations available to common shareholders $ 1,203 $ 1,088 $ 1,069Weighted average common shares outstanding 326 326 326

Basic earnings per share – continuing operations $ 3.69 $ 3.34 $ 3.28

Diluted earnings per share – continuing operations:Income from continuing operations available to common shareholders $ 1,203 $ 1,088 $ 1,069Income impact of assumed conversions 8 12 11

Income from continuing operations available to common shareholders andassumed conversions $ 1,211 $ 1,100 $ 1,080

Weighted average common shares outstanding 326 326 326Incremental shares from assumed conversions 3 5 4

Adjusted weighted average shares – diluted 329 331 330

Diluted earnings per share – continuing operations $ 3.68 $ 3.32 $ 3.27

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Stock-based compensation awards of 3,848,546, 83,901 and 1,897,330 shares of common stock for the yearsended December 31, 2008, 2007 and 2006, respectively, were not included in the computation of dilutedearnings per share because the exercise price of the awards was greater than the average market price of thecommon shares and therefore, the effect would have been antidilutive.

Impairment of Equity Method Investments and Long-Lived Assets

Edison International evaluates the impairment of its investments in projects and other long-lived assets basedon a review of estimated future cash flows expected to be generated whenever events or changes incircumstances indicate the carrying amount of such investments or assets may not be recoverable. If thecarrying amount of the investment or asset exceeds the amount of the expected future cash flows,undiscounted and without interest charges, then an impairment loss for investments in projects and other long-lived assets is recognized in accordance with Accounting Principles Board Opinion No. 18, “The EquityMethod of Accounting for Investments in Common Stock” and SFAS No. 144, respectively. In accordancewith SFAS No. 71, SCE’s impaired assets are recorded as a regulatory asset if it is deemed probable that suchamounts will be recovered from ratepayers.

Income Taxes

Edison International’s eligible subsidiaries are included in Edison International’s consolidated federal incometax and combined state tax returns. Edison International has tax-allocation and payment agreements withcertain of its subsidiaries. For subsidiaries other than SCE, the right of a participating subsidiary to receive ormake a payment and the amount and timing of tax-allocation payments are dependent on the inclusion of thesubsidiary in the consolidated income tax returns of Edison International and other factors including theconsolidated taxable income of Edison International and its includible subsidiaries, the amount of taxableincome or net operating losses and other tax items of the participating subsidiary, as well as the othersubsidiaries of Edison International. There are specific procedures regarding allocations of state taxes. Eachsubsidiary is eligible to receive tax-allocation payments for its tax losses or credits only at such time as EdisonInternational and its subsidiaries generate sufficient taxable income to be able to utilize the participatingsubsidiary’s losses in the consolidated income tax return of Edison International. Under an income tax-allocation agreement approved by the CPUC, SCE’s tax liability is computed as if it filed its federal and stateincome tax returns on a separate return basis.

Edison International applies the asset and liability method of accounting for deferred income taxes as requiredby SFAS No. 109, “Accounting for Income Taxes”. In accordance with FIN 48, “Accounting for Uncertainty inIncome Taxes”, Edison International applies judgment to assess each tax position taken on filed tax returnsand tax positions expected to be taken on future returns to determine whether a tax position is more likelythan not to be sustained and recognized in the financial statements. However, all temporary tax positions,whether or not the more likely than not threshold of FIN 48 is met, are recorded in the financial statements inaccordance with the measurement principles of FIN 48.

As part of the process of preparing its consolidated financial statements, Edison International is required toestimate its income taxes in each jurisdiction in which it operates. This process involves estimating actualcurrent tax expense together with assessing temporary differences resulting from differing treatment of items,such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets andliabilities, which are included within Edison International’s consolidated balance sheet. Edison Internationaltakes certain tax positions it believes are applied in accordance with tax laws. The application of thesepositions is subject to interpretation and audit by the IRS. As further described in Note 4, the IRS has raisedissues in the audit of Edison International’s tax returns with respect to certain leveraged leases of EdisonCapital.

Investment tax credits associated with rate-regulated public utility property are deferred and amortized overthe lives of the properties and production tax credits are recognized in the period in which they are earned.

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Accounting for tax obligations requires judgments, including estimating reserves for potential adverseoutcomes regarding tax positions that have been taken. Management uses judgment in determining whether theevidence indicates it is more likely than not, based solely on the technical merits, that the position will besustained on audit. Management continually evaluates its income tax exposures and provides for allowancesand/or reserves as appropriate, reflected in the captions “Accrued taxes” and “Other deferred credits and long-term liabilities” on the consolidated balance sheets. Income tax expense includes the current tax liability fromoperations and the change in deferred income taxes during the year. Interest expense and penalties associatedwith income taxes are reflected in the caption “Income tax expense” on the consolidated statements of income.

For a further discussion of income taxes, see Note 4.

Intangible Assets

Edison International accounts for acquired intangible assets in accordance with SFAS No. 142. All of theseintangible assets relate to EME. Under SFAS No. 142, acquired intangible assets with indefinite lives are notamortized, rather they are tested for impairment. Intangible assets are periodically reviewed when impairmentindicators are present to assess recoverability from future operations using undiscounted future cash flows. Forproject development rights, the assets are subject to ongoing impairment analysis, such that if a project is nolonger expected, the capitalized costs are written off.

“Other current assets” on Edison International’s consolidated balance sheets includes emission allowancespurchased for use by EME of $88 million and $45 million at December 31, 2008 and 2007, respectively.

“Other long-term assets” on Edison International’s consolidated balance sheets include EME’s projectdevelopment rights, option rights, and purchased emission allowances and the total amounted to $73 millionand $61 million at December 31, 2008 and 2007, respectively. Amortized intangible assets are amortized usingthe straight-line method over five years.

Based on the CAIR requirements, Midwest Generation purchased annual NOX allowances under the newCAIR annual NOX program. The CAIR, issued by the US EPA on March 10, 2005, applies to 28 eastern statesand the District of Columbia and is intended to address ozone and fine particulate matter attainment issues byreducing regional NOX and SO2 emissions. The CAIR was challenged in court by state, environmental andindustry groups. The District of Columbia Circuit Court remanded the CAIR to the US EPA until the US EPApromulgates a revised rule. The timing and substance of the revised rule are not yet clear. Depending on whathappens with respect to the CAIR, and the revised SIPs developed as a consequence of the CAIR, the IllinoisPlants and the Homer City facilities may be subject to additional requirements pursuant to these programs.The Illinois Plants continue to be subject to the CAIR. EME expects that compliance with the CAIR andrevised or additional regulations promulgated to comply with a revised CAIR and/or other air regulatoryrequirements could result in increased capital expenditures and operating expenses beyond those alreadyrequired by the CPS.

Inventory

Inventory is stated at the lower of cost or market, cost being determined by the weighted-average cost methodfor fuel, and the average cost method for materials and supplies.

Leases

Minimum lease payments under operating leases for property, plant and equipment are levelized (totalminimum lease payments divided by the number of years of the lease) and recorded as rent expense over theterms of the leases. Lease payments in excess of the minimum are recorded as rent expense in the yearincurred.

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Capital leases are reported as long-term obligations on the consolidated balance sheets under the caption“Other deferred credits and other long-term liabilities.” In accordance with SFAS No. 71, SCE’s capital leaseamortization expense and interest expense are reflected in the caption “Purchased power” on the consolidatedstatements of income.

See “Lease Commitments” in Note 6 for additional information on operating leases, capital leases and thesale-leaseback transactions.

Margin and Collateral Deposits

Margin and collateral deposits include margin requirements and cash deposited with and received fromcounterparties and brokers as credit support under energy contracts. The amount of margin and collateraldeposits generally varies based on changes in the fair value of the related positions. See “New AccountingPronouncements” below for a discussion of the adoption of FIN No. 39-1. In accordance with FIN No. 39-1,Edison International presents a portion of its margin and cash collateral deposits net with its derivativepositions on its consolidated balance sheets. Amounts recognized for cash collateral provided to others thathave been offset against net derivative liabilities totaled $123 million and $38 million at December 31, 2008and 2007, respectively. Amounts recognized for cash collateral received from others that have been offsetagainst net derivative assets totaled $225 million at December 31, 2008.

New Accounting Pronouncements

Accounting Pronouncements Adopted

In April 2007, the FASB issued FIN No. 39-1. This pronouncement permits companies to offset fair valueamounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cashcollateral (a payable) against fair value amounts recognized for derivative instruments executed with the samecounterparty under a master netting arrangement. In addition, upon the adoption, companies were permitted tochange their accounting policy to offset or not offset fair value amounts recognized for derivative instrumentsunder master netting agreements. Edison International adopted FIN No. 39-1 effective January 1, 2008. Theadoption resulted in netting a portion of margin and cash collateral deposits with derivative positions onEdison International’s consolidated balance sheets, but had no impact on its consolidated statements ofincome. The consolidated balance sheet at December 31, 2007 has been retroactively restated for the change,which resulted in a decrease in net assets (margin and collateral deposits) of $38 million. The consolidatedstatements of cash flows for the years ended December 31, 2007 and 2006 have been retroactively restated toreflect the balance sheet changes, which had no impact on total operating cash flows from continuingoperations.

In February 2007, the FASB issued SFAS No. 159, which provides an option to report eligible financial assetsand liabilities at fair value, with changes in fair value recognized in earnings. Edison International adopted thispronouncement effective January 1, 2008. The adoption of this standard had no impact because EdisonInternational did not make an optional election to report additional financial assets and liabilities at fair value.

In September 2006, the FASB issued SFAS No. 157, which clarifies the definition of fair value, establishes aframework for measuring fair value and expands the disclosures on fair value measurements. EdisonInternational adopted SFAS No. 157 effective January 1, 2008. The adoption did not result in any retrospectiveadjustments to its consolidated financial statements. The accounting requirements for employers’ pension andother postretirement benefit plans were effective at the end of 2008, which was the next measurement date forthese benefit plans. Edison International will adopt this standard for nonrecurring nonfinancial assets andliabilities (AROs) measured or disclosed at fair value during the first quarter of 2009. Since this standard isapplied prospectively, AROs existing before the adoption of the standard will not be adjusted fornonperformance risk. During 2008, Edison International did not apply SFAS No. 157 to new AROs related toits wind facilities constructed during the year. For further discussion, see Note 10.

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On October 10, 2008, the FASB issued FSP SFAS No. 157-3, “Determining the Fair Value of a FinancialAsset When the Market for That Asset Is Not Active.” This position clarifies the application of SFAS No. 157in a market that is not active and provides an example to illustrate key considerations in determining the fairvalue of a financial asset when the market for that financial asset is not active. It also reaffirms the notion offair value as an exit price as of the measurement date. This position was effective upon issuance, includingprior periods for which financial statements have not been issued. The adoption had no impact on EdisonInternational’s consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,”which identifies the sources of accounting principles and the framework for selecting the principles to be usedin the preparation of financial statements for nongovernmental entities that are presented in conformity withGAAP. This statement transfers the GAAP hierarchy from the American Institute of Certified PublicAccountants Statement on Auditing Standards No. 69, “The Meaning of Present Fairly in Conformity WithGenerally Accepted Accounting Principles” to the FASB. SFAS No. 162, was effective on November 15,2008. The adoption of this standard did not have an impact on Edison International’s consolidated results ofoperations, financial position or cash flows.

In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8, “Disclosures by Public Entities(Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities.” For asset transfers,the additional disclosure requirements primarily focus on the transferor’s continuing involvement withtransferred financial assets and the related risks retained. For VIEs, this position requires public enterprises toprovide additional disclosures about their involvement with variable interest entities including the method fordetermining whether an enterprise is the primary beneficiary, the significant judgments and assumptions madeand the details of any financial or other support provided to a VIE. This position was effective for reportingperiods ending after December 15, 2008. The adoption did not have an impact on Edison International’sconsolidated financial position, results of operations or cash flows. See Note 14 for disclosures pertaining toVIEs.

In December 2008, the FASB issued FSP EITF 99-20-1, “Amendments to the Impairment guidance of EITFIssue No. 99-20,” which amends the guidance for purchased beneficial interests to achieve more consistentdetermination of whether an other-than-temporary impairment has occurred for available-for-sale orheld-to-maturity debt securities. This pronouncement was effective for reporting periods ending afterDecember 15, 2008. Because Edison International already evaluates impairment for these securities inaccordance with SFAS No. 115, the adoption did not have an impact on its consolidated financial position,results of operations or cash flows.

Accounting Pronouncements Not Yet Adopted

In December 2007, the FASB issued SFAS No. 141(R), which establishes principles and requirements for howthe acquirer in a business combination recognizes and measures in its financial statements the identifiableassets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition datefair value. SFAS No. 141(R) determines what information to disclose to enable users of the financialstatements to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) appliesprospectively to business combinations for which the acquisition date is on or after fiscal years beginning onor after January 1, 2009. Early adoption is not permitted.

In December 2007, the FASB issued SFAS No. 160, which requires an entity to present minority interest thatreflects the ownership interests in subsidiaries held by parties other than the entity, within the equity sectionbut separate from the entity’s equity in the consolidated financial statements. It also requires the amount ofconsolidated net income attributable to the parent and to the noncontrolling interest to be clearly identified andpresented on the face of the consolidated statement of income; changes in ownership interest be accounted forsimilarly as equity transactions; and, when a subsidiary is deconsolidated, any retained noncontrolling equityinvestment in the former subsidiary and the gain or loss on the deconsolidation of the subsidiary be measured

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at fair value. Edison International will adopt SFAS No. 160 in the first quarter of 2009. In accordance withthis standard, Edison International will reclassify minority interest to a component of shareholders’ equity (atDecember 31, 2008 this amount was $285 million).

In March 2008, the FASB issued SFAS No. 161, which requires additional disclosures related to derivativeinstruments, including how and why an entity uses derivative instruments, how derivative instruments andrelated hedged items are accounted for and how derivative instruments and related hedged items affect anentity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal yearsbeginning after November 15, 2008, with early adoption permitted. Edison International will adoptSFAS No. 161 in the first quarter of 2009. Since SFAS No. 161 impacts disclosures only, the adoption of thisstandard will not have an impact on Edison International’s consolidated results of operations, financial positionor cash flows.

In April 2008, the FASB issued FSP FAS No. 142-3 which amends the factors that should be considered indeveloping renewal or extension assumptions used to determine the useful life of a recognized intangible assetunder SFAS No. 142, “Goodwill and Other Intangible Assets.” The intent of the position is to improve theconsistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period ofexpected cash flows used to measure the fair value of the asset under SFAS No. 141(R) and other GAAP.Edison International will adopt FSP FAS No. 142-3 in the first quarter of 2009. The adoption of the positionwill not have an impact on Edison International’s consolidated results of operations, financial position or cashflows.

In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers” Disclosures about PostretirementBenefit Plan Assets.” This position requires additional plan asset disclosures about the major categories ofassets, the inputs and valuation techniques used to measure fair value, the level within the fair value hierarchy,the effect of using significant unobservable inputs (Level 3) and significant concentrations of risk. Thisposition is effective for years ending after December 15, 2009 and, therefore, Edison International will adoptFSP FAS 132(R)-1 at year-end 2009. FSP FAS 132(R)-1 will impact disclosures only and will not have animpact on Edison International’s consolidated results of operations, financial position or cash flows.

In November 2008, the FASB ratified the consensus in EITF Issue No. 08-6, “Equity Method InvestmentAccounting Considerations.” This issue clarifies the accounting for certain transactions and impairmentconsiderations involving equity method investments. This issue is effective prospectively beginning onJanuary 1, 2009. Edison International expects that the adoption of this issue will not have an impact on itsconsolidated financial statements.

Nuclear Decommissioning

As a result of SCE’s adoption of SFAS No. 143 in 2003, SCE recorded the fair value of its liability for AROs,primarily related to the decommissioning of its nuclear power facilities. At that time, SCE adjusted its nucleardecommissioning obligation, capitalized the initial costs of the ARO into a nuclear-related ARO regulatoryasset, and also recorded an ARO regulatory liability as a result of timing differences between the recognitionof costs recorded in accordance with SFAS No. 143 and the recovery of the related asset retirement coststhrough the rate-making process.

SCE plans to decommission its nuclear generating facilities by a prompt removal method authorized by theNRC. Decommissioning is expected to begin after the plants’ operating licenses expire. The operating licensescurrently expire in 2022 for San Onofre Units 2 and 3, and in 2024, 2025 and 2027 for the Palo Verde units.Decommissioning costs, which are recovered through nonbypassable customer rates over the term of eachnuclear facility’s operating license, are recorded as a component of depreciation expense, with a correspondingcredit to the ARO regulatory liability. The earnings impact of amortization of the ARO asset included withinthe unamortized nuclear investment and accretion of the ARO liability, both established under SFAS No. 143,

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are deferred as increases to the ARO regulatory liability account, with no impact on earnings. See Note 8 foran analysis of the ARO liability.

SCE has collected in rates amounts for the future costs of removal of its nuclear assets, and has placed thoseamounts in independent trusts. The cost of removal amounts, in excess of fair value collected for assets notlegally required to be removed, are classified as regulatory liabilities.

SCE’s nuclear decommissioning trusts are accounted for in accordance with SFAS No. 115, and due toregulatory recovery of SCE nuclear decommissioning expense, rate-making accounting treatment is applied toall nuclear decommissioning trust activities in accordance with SFAS No. 71. As a result, nucleardecommissioning activities do not affect SCE’s earnings.

SCE’s nuclear decommissioning trust investments are classified as available-for-sale. SCE has debt and equityinvestments for the nuclear decommissioning trust funds. Due to regulatory mechanisms, earnings and realizedgains and losses (including other-than-temporary impairments) have no impact on electric utility revenue.Unrealized gains and losses on decommissioning trust funds increase or decrease the trust asset and the relatedregulatory asset or liability and have no impact on electric utility revenue or decommissioning expense. SCEreviews each security for other-than-temporary impairment losses on the last day of each month compared tothe last day of the previous month. If the fair value on both days is less than the cost for that security, SCEwill recognize a realized loss for the other-than-temporary impairment. If the fair value is greater or less thanthe cost for that security at the time of sale, SCE will recognize a related realized gain or loss, respectively.For a further discussion about nuclear decommissioning trusts see “Nuclear Decommissioning Commitment”in Note 6 and “Nuclear Decommissioning Trusts” in Note 10.

Planned Major Maintenance

Certain plant facilities require major maintenance on a periodic basis. These costs are expensed as incurred.

Project Development Costs

Edison International capitalizes direct costs incurred in developing new projects upon attainment of principalactivities needed to commence procurement and construction. These costs consist of professional fees, salaries,permits, and other directly related development costs incurred by Edison International. The capitalized costsare amortized over the life of operational projects or charged to expense if Edison International determines thecosts to be unrecoverable.

Property and Plant

Utility Plant

Utility plant additions, including replacements and betterments, are capitalized. Such costs include directmaterial and labor, construction overhead, a portion of administrative and general costs capitalized at a rateauthorized by the CPUC, and AFUDC. AFUDC represents the estimated cost of debt and equity funds thatfinance utility-plant construction. Currently, AFUDC debt and equity is capitalized during certain plantconstruction and reported in interest expense and other nonoperating income, respectively. AFUDC isrecovered in rates through depreciation expense over the useful life of the related asset. Depreciation of utilityplant is computed on a straight-line, remaining-life basis.

On November 26, 2007, the FERC issued an order granting incentives on three of SCE’s largest proposedtransmission projects, DPV2, Tehachapi Transmission Project (“Tehachapi”), and Rancho Vista SubstationProject (“Rancho Vista”). The order permits SCE to include in rate base 100% of prudently-incurred capitalexpenditures during construction of all three projects. On February 29, 2008, the FERC approved SCE’srevision to its Transmission Owner Tariff to collect 100% of construction work in progress (CWIP) for theseprojects in rate base and earn a return on equity, rather than capitalizing AFUDC. SCE implemented the

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CWIP rate, subject to refund, on March 1, 2008. For further discussion, see “FERC Transmission Incentives”in Note 6.

Depreciation expense stated as a percent of average original cost of depreciable utility plant was, on acomposite basis, 4.3% for 2008, 4.2% for 2007 and 4.2% for 2006.

AFUDC – equity was $54 million in 2008, $46 million in 2007 and $32 million in 2006. AFUDC – debt was$27 million in 2008, $24 million in 2007 and $18 million in 2006.

Replaced or retired property costs are charged to the accumulated provision for depreciation. Cash paymentsfor removal costs less salvage reduce the liability for AROs.

In May 2003, the Palo Verde units returned to traditional cost-of-service ratemaking while San Onofre Units 2and 3 returned to traditional cost-of-service ratemaking in January 2004. SCE’s nuclear plant investmentsmade prior to the return to cost-of-service ratemaking are recorded as regulatory assets on its consolidatedbalance sheets. Since the return to cost-of-service ratemaking, capital additions are recorded in utility plant.These classifications do not affect the rate-making treatment for these assets.

Estimated useful lives (authorized by the CPUC) and weighted-average useful lives of SCE’s property, plantand equipment, are as follows:

EstimatedUseful Lives

Weighted-AverageUseful Lives

Generation plant 38 years to 69 years 40 yearsDistribution plant 30 years to 60 years 40 yearsTransmission plant 35 years to 65 years 45 yearsOther plant 5 years to 60 years 20 years

Nuclear fuel is recorded as utility plant (nuclear fuel in the fabrication and installation phase is recorded asconstruction in progress) in accordance with CPUC rate-making procedures. Nuclear fuel is amortized usingthe units of production method.

Nonutility Property

Nonutility property, including leasehold improvements and construction in progress, is capitalized at cost.Interest incurred on borrowed funds that finance construction and project development costs are alsocapitalized. Capitalized interest was $32 million in 2008, $24 million in 2007 and $8 million in 2006. SCE’sMountainview plant is included in nonutility property in accordance with the rate-making treatment. EME’scapitalized interest is amortized over the depreciation period of the major plant and facilities for the respectiveproject. SCE’s capitalized interest is generally amortized over 30 years (the life of the purchase-poweragreement under which the Mountainview plant operates).

Depreciation and amortization is primarily computed on a straight-line basis over the estimated useful lives ofnonutility properties and over the shorter of the useful life or the lease term for leasehold improvements.Depreciation expense stated as a percent of average original cost of depreciable nonutility property was, on acomposite basis, 3.9% for 2008, 4.0% for 2007 3.9% for 2006.

Emission allowances were acquired by EME as part of its Illinois plants and Homer City facilitiesacquisitions. Although these emission allowances are freely transferable, EME intends to use substantially allof the emission allowances in the normal course of its business to generate electricity. Accordingly, EdisonInternational has classified emission allowances expected to be used by EME to generate power as part ofnonutility property. These acquired emission allowances will be amortized on a straight-line basis.

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Estimated useful lives for nonutility property are as follows:

Furniture and equipment 3 years to 20 yearsBuilding, plant and equipment 3 years to 30 yearsEmission allowances 25 years to 34 yearsLand easements 60 yearsLeasehold improvements Shorter of life of lease or estimated useful life

Asset Retirement Obligation

Edison International accounts for its asset retirement obligations in accordance with SFAS No. 143 andFIN 47. AROs related to decommissioning of its nuclear power facilities are based on site-specific studies.The initial establishment of a nuclear-related ARO is at fair value and results in a corresponding regulatoryasset. See “Nuclear Decommissioning” above for further discussion. Over time, the liability is increased foraccretion each period. Edison International’s conditional AROs are recorded at fair value in the period inwhich it is incurred if the fair value can be reasonably estimated even though uncertainty exists about thetiming and/or method of settlement. When the liability is initially recorded, the cost is capitalized byincreasing the carrying amount of the related long-lived asset. Over time, the liability is increased foraccretion each period, and the capitalized cost is depreciated over the useful life of the related asset.Settlement of an ARO liability, for an amount other than its recorded amount, results in a gain or loss.

Purchased-Power

From January 17, 2001 to December 31, 2002, the CDWR purchased power on behalf of SCE’s customers forSCE’s residual net short power position (the amount of energy needed to serve SCE’s customers in excess ofSCE’s own generation and power-purchase contracts). Additionally, the CDWR signed long-term contracts thatprovide power for SCE’s customers. Effective January 1, 2003, SCE resumed power procurementresponsibilities for its residual net short position. SCE acts as a billing agent for the CDWR power, and anypower purchased by the CDWR for delivery to SCE’s customers is not considered a cost to SCE.

Receivables

SCE records an allowance for uncollectible accounts, generally as determined by the average percentage ofamounts written-off in prior periods. SCE assesses its customers a late fee of 0.9% per month, beginning21 days after the bill is prepared. Inactive accounts are written off after 180 days.

Regulatory Assets and Liabilities

In accordance with SFAS No. 71, SCE records regulatory assets, which represent probable future recovery ofcertain costs from customers through the rate-making process, and regulatory liabilities, which representprobable future credits to customers through the rate-making process. See Note 11 for additional disclosuresrelated to regulatory assets and liabilities.

Related Party Transactions

Specified administrative services such as payroll and employee benefit programs, performed by EdisonInternational or SCE employees, are shared among all subsidiaries of Edison International, and the cost ofthese corporate support services are allocated to all subsidiaries. Costs are allocated based on one of thefollowing formulas: percentage of time worked, relative amount of equity in investment, number of employees,or multi-factor method (operating revenue, operating expenses, total assets and number of employees). Inaddition, services of Edison International (or SCE) employees are sometimes directly requested by an EdisonInternational subsidiary and these services are performed for the subsidiary’s benefit. Labor and expenses ofthese directly requested services are specifically identified and billed at cost.

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Four EME subsidiaries have 49% to 50% ownership in partnerships that sell electricity generated by theirproject facilities to SCE under long-term power purchase agreements with terms and pricing approved by theCPUC. Beginning March 31, 2004, Edison International consolidates these projects. See Note 14 for furtherinformation regarding VIEs.

An indirect wholly owned affiliate of EME has entered into operation and maintenance agreements withpartnerships in which EME has a 50% or less ownership interest. EME recorded nonutility power generationrevenue under these agreements of $31 million in 2008, $30 million in 2007 and $26 million in 2006. EME’saccounts receivable with this affiliate totaled $10 million and $11 million at December 31, 2008 and 2007,respectively.

During the first quarter of 2008, a subsidiary of EME was awarded by SCE, through a competitive biddingprocess, a ten-year power sales contract with SCE for the output of a 479 MW gas-fired peaking facilitylocated in the City of Industry, California, which is referred to as the “Walnut Creek” project. The power salesagreement was approved by the CPUC on September 18, 2008 and by the FERC on October 2, 2008.Deliveries under the power sales agreement are scheduled to commence in 2013. See Note 6 for furtherinformation.

Restricted Cash

Edison International had total restricted cash of $46 million at December 31, 2008 and $51 million atDecember 31, 2007. The restricted amounts included in current assets serve as collateral at Edison Capital foroutstanding letters of credit. The restricted amounts included in other long-term assets are primarily to payamounts required for lease payments and to provide collateral at EME.

Revenue Recognition

Electric utility revenue is recognized as electricity is delivered and includes amounts for services rendered butunbilled at the end of each reporting period. Rates charged to customers are based on CPUC-authorized andFERC-approved revenue requirements. CPUC rates are implemented upon final approval. FERC rates are oftenimplemented on an interim basis at the time when the rate change is filed. Revenue collected prior to a finalFERC approval decision is subject to refund. SCE’s revenue requirements are based on its cost of service,referred to as base rate revenue requirement, and also provide recovery of pass-through costs under ratemakingmechanisms (balancing accounts) authorized by the CPUC. The base rate revenue requirement provides anopportunity to recover operation and maintenance expenses, capital-related carrying costs and earn anauthorized rate of return. The revenue requirement for pass-through costs provides recovery of fuel andpurchased-power expenses, demand-side management programs, nuclear decommissioning, public purposeprograms, certain operation and maintenance expenses and depreciation expense related to certain projects.SCE recognizes electric utility revenue equal to its authorized base rate revenue requirement and equal toactual costs incurred for pass-through costs.

The CPUC-authorized decoupling revenue mechanisms allow for differences in revenue resulting from actualand forecast volumetric electricity sales to be collected from or refunded to ratepayers therefore suchdifferences do not impact electric utility revenue. Differences between authorized operating costs included inSCE’s base rate revenue requirement and actual operating costs incurred, other than pass-through costs, do notimpact electric utility revenue, but have an impact on earnings.

Since January 17, 2001, power purchased by the CDWR or through the ISO for SCE’s customers is notconsidered a cost to SCE because SCE is acting as an agent for these transactions. Furthermore, amountsbilled to ($2.2 billion in 2008, $2.3 billion in 2007 and $2.5 billion in 2006) and collected from SCE’scustomers for these power purchases, CDWR bond-related costs (effective November 15, 2002) and a portionof direct access exit fees (effective January 1, 2003) are being remitted to the CDWR and are not recognizedas electric utility revenue by SCE.

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Generally, nonutility power generation revenue is recorded as electricity is generated or services are providedunless it is subject to SFAS No. 133 and does not qualify for the normal purchases and sales exception.EME’s subsidiaries enter into power and fuel hedging, optimization transactions and energy trading contracts,all subject to market conditions. One of EME’s subsidiaries executes these transactions primarily through theuse of physical forward commodity purchases and sales and financial commodity swaps and options. Withrespect to its physical forward contracts, EME’s subsidiaries generally act as the principal, take title to thecommodities, and assume the risks and rewards of ownership. Therefore, EME’s subsidiaries record settlementof nontrading physical forward contracts on a gross basis. Consistent with EITF No. 03-11, “ReportingRealized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133,“Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes,” EMEnets the cost of purchased power against related third party sales in markets that use locational marginalpricing, currently PJM. Financial swap and option transactions are settled net and, accordingly, EME’ssubsidiaries do not take title to the underlying commodity. Therefore, gains and losses from settlement offinancial swaps and options are recorded net in nonutility power generation revenue. Managed risks typicallyinclude commodity price risk associated with fuel purchases and power sales. In addition, nonutility powergeneration revenue includes revenue under certain long-term power sales contracts subject to EITF No. 91-6,“Revenue Recognition of Long-term Power Sales Contracts,” which is recognized based on the outputdelivered at the lower of the amount billable or the average rate over the contract term. The excess of theamounts billed over the portion recorded as nonutility power generation revenue is reflected in the caption“Other deferred credits and other long-term liabilities” on the consolidated balance sheets.

Financial services and other revenue are generally derived from leveraged leases, which are recorded byrecognizing income over the term of the lease so as to produce a constant rate of return based on theinvestment leased.

Gains and losses from sale of assets are recognized at the time of the transaction.

Sales and Use Taxes

SCE bills certain sales and use taxes levied by state or local governments to its customers. Included in thesesales and use taxes are franchise fees, which SCE pays to various municipalities (based on contracts with thesemunicipalities) in order to operate within the limits of the municipality. SCE bills these franchise fees to itscustomers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless ofSCE’s ability to collect from the customer, are accounted for on a gross basis and reflected in electric utilityrevenue and other operation and maintenance expense. SCE’s franchise fees billed to customers and recordedas electric utility revenue were $103 million, $104 million and $107 million for the years ended December 31,2008, 2007 and 2006, respectively. When SCE acts as an agent, and the tax is not required to be remitted if itis not collected from the customer, the taxes are accounted for on a net basis. Amounts billed to and collectedfrom customers for these taxes are being remitted to the taxing authorities and are not recognized as electricutility revenue.

Short-term Investments

At different times during 2008 and 2007, Edison International held various variable rate demand notes relatedto short-term cash management activities. The interest rate process for these securities allow for a resetting ofinterest rates related to changes in terms and/or credit quality, similar to cash and cash equivalents. Inaccordance with SFAS No. 115, if on hand at the end of a period, these notes would be classified as short-term available-for-sale investment securities and recorded at fair value. There were no outstanding notes as ofDecember 31, 2008 and 2007. Both sales and purchases of the notes were $.1 billion, $9.5 billion and$7.5 billion for the years ended December 31, 2008, 2007 and 2006, respectively. There were no realized orunrealized gains or losses.

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In addition, at December 31, 2008 and 2007, Edison International had classified all marketable debt securitiesas held-to-maturity and carried at amortized cost plus accrued interest which approximated their fair value.Gross unrealized holding gains and losses were not material. Edison International’s short-term investments,which all mature within one year, consisted of the following:


Commercial paper $ 1 $ 32Certificates of deposit 3 41U.S. Treasury securities — 7Corporate bonds — 1Money market funds 3 —

Total $ 7 $ 81

Stock-Based Compensation

Stock options, performance shares, deferred stock units and, beginning in 2007, restricted stock units havebeen granted under Edison International’s long-term incentive compensation programs. Edison Internationalusually does not issue new common stock for equity awards settled. Rather, a third party is used to facilitatethe exercise of stock options and the purchase and delivery of outstanding common stock for settlement ofoption exercises, performance shares, and restricted stock units. Performance shares earned are settled half incash and half in common stock; however, Edison International has discretion under certain of the awards topay the half subject to cash settlement in common stock. Deferred stock units granted to management aresettled in cash, not stock and represent a liability. Restricted stock units are settled in common stock; however,Edison International will substitute cash awards to the extent necessary to pay tax withholding or anygovernment levies.

On April 26, 2007, Edison International’s shareholders approved a new incentive plan (the 2007 PerformanceIncentive Plan) that includes stock-based compensation. No additional awards were granted under EdisonInternational’s prior stock-based compensation plans on or after April 26, 2007, and all future issuances willbe made under the new plan. The maximum number of shares of Edison International’s common stock thatmay be issued or transferred pursuant to awards under the new incentive plan is 8.5 million shares, plus thenumber of any shares subject to awards issued under Edison International’s prior plans and outstanding as ofApril 26, 2007, which expire, cancel or terminate without being exercised or shares being issued. As ofDecember 31, 2008, Edison International had approximately 5.8 million shares remaining for future issuanceunder its stock-based compensation plan. For further discussion see “Stock-Based Compensation” in Note 5.

SFAS No. 123(R) requires companies to use the fair value accounting method for stock-based compensation.Edison International implemented SFAS No. 123(R) in the first quarter of 2006 and applied the modifiedprospective transition method. Under the modified prospective method, SFAS No. 123(R) was applied effectiveJanuary 1, 2006 to the unvested portion of awards previously granted and will be applied to all prospectiveawards. Prior financial statements were not restated under this method. The new accounting standard resultedin the recognition of expense for all stock-based compensation awards. In addition, Edison Internationalelected to calculate the pool of windfall tax benefits as of the adoption of SFAS No. 123(R) based on themethod (also known as the short-cut method) proposed in FSP FAS 123(R)-3, “Transition Election toAccounting for the Tax Effects of Share-Based Payment Awards.” Prior to adoption of SFAS No. 123(R),Edison International presented all tax benefits of deductions resulting from the exercise of stock options as acomponent of operating cash flows under the caption “Other liabilities” in the consolidated statements of cashflows. SFAS No. 123(R) requires the cash flows resulting from the tax benefits that occur from estimated taxdeductions in excess of the compensation cost recognized for those options (excess tax benefits) to beclassified as financing cash flows. The $10 million, $45 million and $27 million of excess tax benefits areclassified as financing cash flows in 2008, 2007 and 2006, respectively. Due to the adoption ofSFAS No. 123(R), Edison International recorded a cumulative effect adjustment that increased net income by

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approximately $1 million, net of tax, in the first quarter of 2006, mainly to reflect the change in the valuationmethod for performance shares classified as liability awards and the use of forfeiture estimates.

Prior to January 1, 2006, Edison International accounted for these plans using the intrinsic value method.Upon grant, no stock-based compensation cost for stock options was reflected in net income, as the grant datewas the measurement date, and all options granted under these plans had an exercise price equal to the marketvalue of the underlying common stock on the date of grant. Previously, stock-based compensation cost forperformance shares was remeasured at each reporting period and related compensation expense was adjusted.As discussed above, effective January 1, 2006, Edison International implemented a new accounting standardthat requires companies to use the fair value accounting method for stock-based compensation resulting in therecognition of expense for all stock-based compensation awards. Edison International recognizes stock-basedcompensation expense on a straight-line basis over the requisite service period. Because SCE capitalizes aportion of cash-based compensation and SFAS No. 123(R) requires stock-based compensation to be recordedsimilarly to cash-based compensation, SCE capitalizes a portion of its stock-based compensation related toboth unvested awards and new awards. Edison International recognizes stock-based compensation expense forawards granted to retirement-eligible participants as follows: for stock-based awards granted prior toJanuary 1, 2006, Edison International recognized stock-based compensation expense over the explicit requisiteservice period and accelerated any remaining unrecognized compensation expense when a participant actuallyretired; for awards granted or modified after January 1, 2006 to participants who are retirement-eligible or willbecome retirement-eligible prior to the end of the normal requisite service period for the award, stock-basedcompensation will be recognized on a prorated basis over the initial year or over the period between the dateof grant and the date the participant first becomes eligible for retirement. If Edison International recognizedstock-based compensation expense for awards granted prior to January 1, 2006, over a period to the date theparticipant first became eligible for retirement, stock-based compensation expense would have decreased$3 million and $8 million for 2007 and 2006, respectively.

Note 2. Derivative Instruments and Hedging Activities

EME recorded net gains of approximately $171 million, $149 million and $137 million in 2008, 2007 and2006, respectively, arising from energy trading activities, which are reflected in nonutility power generationrevenue on the consolidated statements of income (including earnings from restructuring non-utility generatorcontracts). EME netted 4.1 million MWh of sales and purchases of physically settled, gross purchases andsales during both 2008 and 2007 and 4.3 million MWh during 2006.

EME recorded net unrealized gains (losses) arising from nontrading derivative activities of $15 million,$(35) million and $65 million in 2008, 2007 and 2006, respectively, which are reflected in nonutility powergeneration revenue on the consolidated statements of income.

SCE is exposed to commodity price risk associated with its purchases for additional capacity and ancillaryservices to meet its peak energy requirements as well as exposure to natural gas prices associated with powerpurchased from QFs, fuel tolling arrangements, and its own gas-fired generation, including the Mountainviewplant. SCE’s realized gains and losses arising from derivative instruments are reflected in purchased-powerexpense and are recovered through the ERRA mechanism. Unrealized gains and losses have no impact onpurchased-power expense due to regulatory mechanisms. As a result, realized and unrealized gains and lossesdo not affect earnings, but may temporarily affect cash flows. The following is a summary of purchased-powerexpense:

In millions For the year ended December 31, 2008 2007 2006

Purchased-power $ 3,816 $ 3,179 $ 2,940Realized losses on economic hedging activities – net 60 132 339Energy settlements and refunds (31) (76) (180)

Total purchased-power expense $ 3,845 $ 3,235 $ 3,099

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Unrealized (gains) losses on economic hedging were $638 million in 2008, $(94) million in 2007, and$237 million in 2006. Changes in realized and unrealized gains and losses on economic hedging activitieswere primarily due to significant decreases in forward natural gas prices in 2008 compared to 2007. Changesin realized and unrealized gains and losses on economic hedging activities in 2007 compared to 2006 wereprimarily due to changes in SCE’s gas hedge portfolio mix as well as an increase in the natural gas futuresmarket in 2007.

Note 3. Liabilities and Lines of Credit

Long-Term Debt

Almost all SCE properties are subject to a trust indenture lien. SCE has pledged first and refunding mortgagebonds as collateral for borrowed funds obtained from pollution-control bonds issued by government agencies.SCE used these proceeds to finance construction of pollution-control facilities. SCE has a debt covenant thatrequires a debt to total capitalization ratio be met. At December 31, 2008, SCE was in compliance with thisdebt covenant. Bondholders have limited discretion in redeeming certain pollution-control bonds, and SCE hasarranged with securities dealers to remarket or purchase them if necessary.

Redemption of MEHC Senior Secured Notes

On June 25, 2007, MEHC redeemed in full its senior secured notes. As a result of the redemption, EME is nolonger subject to financial and investment restrictions that were contained in the indenture pursuant to whichthe senior secured notes were issued.

Senior Notes Offering

In 2007, EME issued $1.2 billion of its 7.00% senior notes due 2017, $800 million of its 7.20% senior notesdue 2019 and $700 million of its 7.625% senior notes due 2027. EME pays interest on the senior notes onMay 15 and November 15 of each year, beginning on November 15, 2007. The net proceeds were used,together with cash on hand, to purchase substantially all of EME’s outstanding 7.73% senior notes due 2009and all of Midwest Generation’s 8.75% second priority senior secured notes due 2034; repay the outstandingbalance of Midwest Generation’s senior secured term loan facility; and make a dividend payment of$899 million to MEHC which enabled MEHC to purchase substantially all of its 13.5% senior secured notesdue 2008. Edison International recorded a total pre-tax loss of $241 million ($148 million after tax) on earlyextinguishment of debt in 2007.

The senior notes are redeemable by EME at any time at a price equal to 100% of the principal amount, plusaccrued and unpaid interest and liquidated damages, if any, of the senior notes plus a “make-whole” premium.The senior notes are EME’s senior unsecured obligations, ranking equal in right of payment to all of EME’sexisting and future senior unsecured indebtedness, and will be senior to all of EME’s future subordinatedindebtedness. EME’s secured debt and its other secured obligations are effectively senior to the senior notes tothe extent of the value of the assets securing such debt or other obligations. None of EME’s subsidiaries haveguaranteed the senior notes and, as a result, all the existing and future liabilities of EME’s subsidiaries areeffectively senior to the senior notes.

In connection with Midwest Generation’s financing activities, EME has given a first priority security interestin substantially all the coal-fired generating plants owned by Midwest Generation and the assets relating tothose plants and receivables of EMMT directly related to Midwest Generation’s hedging activities. Theamount of assets pledged or mortgaged totaled approximately $2.9 billion at December 31, 2008. In additionto these assets, Midwest Generation’s membership interests and the capital stock of Edison Mission MidwestHoldings were pledged. Emission allowances have not been pledged.

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Long-term debt is:


First and refunding mortgage bonds:2009 – 2038 (4.65% to 6.0% and variable) $ 4,875 $ 3,375

Pollution-control bonds:2015 – 2035 (2.9% to 5.55% and variable) 1,196 1,196

Bonds repurchased (249) (37)Debentures and notes:

2009 – 2053 (noninterest-bearing to 8.75%) 5,320 4,512Long-term debt due within one year (174) (18)Unamortized debt discount – net (18) (12)

Total $ 10,950 $ 9,016

Note: Rates and terms as of December 31, 2008.

The interest rates on one issue of SCE’s pollution control bonds insured by FGIC, totaling $249 million, werereset every 35 days through an auction process. Due to a loss of confidence in the creditworthiness of thebond insurers, there was a significant reduction in market liquidity for auction rate bonds and interest rates onthese bonds increased. Consequently, SCE purchased in the secondary market $37 million of its auction ratebonds in December 2007 and the remaining $212 million during the first three months of 2008. In March2008, SCE converted the issue to a variable rate mode and terminated the FGIC insurance policy. SCEcontinues to hold the bonds which remain outstanding and have not been retired or cancelled.

Long-term debt maturities and sinking-fund requirements for the next five years are: 2009 – $174 million;2010 – $300 million; 2011 – $14 million; 2012 – $867 million and 2013 – $517 million.

Short-Term Debt

SCE short-term debt is generally used to finance fuel inventories, balancing account undercollections andgeneral, temporary cash requirements including power purchase payments. At December 31, 2008, theoutstanding short-term debt was $1.89 billion at a weighted-average interest rate of 0.67%. This short-termdebt is supported by a $2.5 billion credit line. At December 31, 2007, the outstanding short-term debt was$500 million at a weighted-average interest rate of 5.29%. This short-term debt was supported by a$2.5 billion credit line. See below in “Credit Agreements.”

Edison International (parent) short-term debt is generally used for liquidity purposes. At December 31, 2008,the outstanding short-term debt was $250 million at a weighted-average interest rate of 0.85%. This short-termdebt is supported by a $1.5 billion credit line. Edison International parent had no short-term debt outstandingat December 31, 2007. See below in “Credit Agreements.”

Credit Agreements

During 2007, EME amended its existing $500 million secured credit facility maturing on June 15, 2012,increasing the total borrowings available thereunder to $600 million, and subject to the satisfaction ofconditions as set forth in the secured credit facility, EME is permitted to increase the amount available underthe secured credit facility to an amount that does not exceed 15% of EME’s consolidated net tangible assets,as defined in the secured credit facility. Loans made under this credit facility bear interest, at EME’s election,at either LIBOR (which is based on the interbank Eurodollar market) or the base rate (which is calculated asthe higher of Citibank, N.A.’s publicly announced base rate and the federal funds rate in effect from time totime plus 0.50%) plus, in both cases, an applicable margin. The applicable margin depends on EME’s debtratings. At December 31, 2008, EME had borrowings outstanding of $376 million, at the applicable margin of1.50%, classified as long-term debt and $129 million of letters of credit outstanding under this credit facility.

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The credit facility contains financial covenants which require EME to maintain a minimum interest coverageratio and a maximum corporate debt to corporate capital ratio. A failure to meet a ratio threshold could triggerother provisions, such as mandatory prepayment provisions or restrictions on dividends. At December 31,2008, EME met both these ratio tests.

As security for its obligations under this credit facility, EME pledged its ownership interests in the holdingcompanies through which it owns its interests in the Illinois Plants, the Homer City facilities, the Westsideprojects and the Sunrise project. EME also granted a security interest in an account into which all distributionsreceived by it from the Big 4 projects are deposited. EME is free to use these proceeds unless an event ofdefault occurs under the credit facility.

During 2007, Midwest Generation also amended and restated its existing $500 million senior secured workingcapital facility. Borrowings made under this credit facility bear interest at LIBOR + 0.55%, except if averageutilized commitments during a period exceed $250 million, in which case the margin increases to 0.65%which was the case at December 31, 2008. The working capital facility matures in 2012, with an option toextend for up to two years. The working capital facility contains financial covenants which require MidwestGeneration to maintain a debt to capitalization ratio of no greater than 0.60 to 1. At December 31, 2008, thedebt to capitalization ratio was 0.28 to 1. Midwest Generation uses its secured working capital facility toprovide credit support for its hedging activities and for general working capital purposes. Midwest Generationcan also support its hedging activities by granting liens to eligible hedge counterparties. As of December 31,2008, Midwest Generation had borrowings outstanding of $475 million classified as long-term debt and$3 million of letters of credit had been utilized under the working capital facility.

In March 2008, SCE amended its $2.5 billion credit facility, extending the maturity to February 2013. Therelated borrowings are classified as short-term debt as it is expected to be repaid by year-end 2009. Also, inMarch, 2008 Edison International amended its $1.5 billion credit facility, extending the maturity to February2013. For both SCE and Edison International, the amendment also provides four extension options which, ifall exercised, and agreed to by lenders, will result in a final termination in February 2017.

During 2008, Edison International (parent) and its subsidiaries, made borrowings under their respective creditagreements.

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of theU.S. Bankruptcy Code. A subsidiary of Lehman Brothers Holdings, Lehman Brothers Bank, FSB, is one of thelenders in SCE’s and Edison International (parent) credit agreement representing a total commitment of$106 million and $74 million, respectively. Lehman Brothers Bank, FSB had funded $25 million of SCE’sborrowing request during the second quarter of 2008, but declined SCE’s requests during the second half of2008 for funding of approximately $57 million. This subsidiary fully funded $12 million of EdisonInternational (parent) borrowing request, which remains outstanding.

A subsidiary of Lehman Brothers Holdings, Lehman Commercial Paper Inc., is one of the lenders in EME’scredit agreement representing a commitment of $36 million. In September 2008, Lehman Commercial PaperInc. declined requests for funding under EME’s credit agreement. Another subsidiary of Lehman BrothersHoldings, Lehman Brothers Commercial Bank, Inc., is one of the lenders in the Midwest Generation workingcapital facility. This subsidiary fully funded $42 million of Midwest Generation’s borrowing requests, whichremains outstanding. At December 31, 2008, Lehman Brothers Commercial Bank’s share of the amountavailable to draw under the Midwest Generation working capital facility was $2 million.

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The following table summarizes the status of these credit facilities at December 31, 2008:

In millions SCE EMG

EdisonInternational

(parent)

Commitment $ 2,500 $ 1,100 $ 1,500Less: Unfunded commitment from Lehman Brothers subsidiary (81) (36) (62)

2,419 1,064 1,438Outstanding borrowings (1,893) (851) (250)Outstanding letters of credit (141) (132) —

Amount available $ 385 $ 81 $ 1,188

The following table summarizes the status of these credit facilities at December 31, 2007:

In millions SCE EMG

EdisonInternational

(parent)

Commitment $ 2,500 $ 1,100 $ 1,500Less: Unfunded commitment from Lehman Brothers subsidiary — — —

2,500 1,100 1,500Outstanding borrowings (500) — —Outstanding letters of credit (229) (93) —

Amount available $ 1,771 $ 1,007 $ 1,500

Note 4. Income Taxes

The sources of income (loss) before income taxes are:


Domestic $ 1,809 $ 1,570 $ 1,636Foreign 2 22 29

Total continuing operations 1,811 1,592 1,665

Discontinued operations 5 3 119Accounting change — — 1

Total $ 1,816 $ 1,595 $ 1,785

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The components of income tax expense (benefit) by location of taxing jurisdiction are:


Current:Federal $ 183 $ 359 $ 652State 80 95 149Foreign — — 1

263 454 802

Deferred:Federal 307 57 (159)State 26 (19) (61)

333 38 (220)

Total continuing operations 596 492 582Discontinued operations 5 5 22

Total $ 601 $ 497 $ 604

The components of the net accumulated deferred income tax liability are:


Deferred tax assets:Property-related $ 556 $ 458Unrealized gains and losses 77 400Regulatory balancing accounts 436 519Decommissioning 168 182Accrued charges 108 158Loss and credit carryforwards — 16Pension and PBOPs 203 177Other 490 545

Total $ 2,038 $ 2,455

Deferred tax liabilities:Property-related $ 4,079 $ 3,636Leveraged leases 2,313 2,316Capitalized software costs 231 128Regulatory balancing accounts 433 521Unrealized gains and losses 70 393Other 525 490

Total $ 7,651 $ 7,484

Accumulated deferred income tax liability – net $ 5,613 $ 5,029

Classification of accumulated deferred income taxes – net:Included in total deferred credits and other liabilities $ 5,717 $ 5,196Included in current assets $ 104 $ 167

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The federal statutory income tax rate is reconciled to the effective tax rate from continuing operations asfollows:


Federal statutory rate 35.0% 35.0% 35.0%State tax – net of federal benefit 4.2 4.1 3.7Property-related (3.2) (0.2) 0.2Housing and production credits (3.1) (2.9) (2.1)Tax reserve adjustments 0.7 (3.5) 2.5Resolution of state audit issue — — (3.0)Other (0.7) (1.6) (1.3)

Effective tax rate 32.9% 30.9% 35.0%

Edison International’s composite federal and state statutory income tax rate was approximately 40% (net of thefederal benefit for state income taxes) for all periods presented. The lower effective tax rate of 32.9% in 2008as compared to the statutory rate was primarily due to production and low income housing credits at EMG andsoftware and property related flow through deductions at SCE. The lower effective tax rate of 30.9% in 2007as compared to the statutory rate was primarily due to reductions made to the income tax reserve to reflectprogress made in an administrative appeals process with the IRS related to SCE’s income tax treatment ofcertain costs associated with environmental remediation, due to reductions made to the income tax reserve toreflect a settlement of state tax audit issues and due to production and low income housing credits at EMG.The lower effective tax rate of 35.0% in 2006 as compared to the statutory rate was primarily due to asettlement reached with the California Franchise Tax Board regarding a state apportionment issue and fromlow income housing and wind production tax credits at EMG. These reductions were partially offset by taxreserve accruals at SCE.

Edison International and its subsidiaries had California net operating loss carryforwards with expirations datesbeginning in 2012 of $53 million and $54 million at December 31, 2008 and 2007, respectively.

Accounting for Uncertainty in Income Taxes

FIN 48 requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a taxposition by determining if the weight of the available evidence indicates it is more likely than not, basedsolely on the technical merits, that the position will be sustained on audit. Edison International has filedaffirmative tax claims related to tax positions, which, if accepted, could result in refunds of taxes paid oradditional tax benefits for positions not reflected on filed original tax returns. FIN 48 requires the disclosureof all unrecognized tax benefits, which includes the reserves recorded for tax positions on filed tax returns andthe unrecognized portion of affirmative claims.

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Unrecognized Tax Benefits

The following table provides a reconciliation of unrecognized tax benefits from January 1 to December 31 andthe reasons for such changes:

In millions 2008 2007

Balance at January 1 $ 2,114 $ 2,160Tax positions taken during the current year

Increases 118 69Decreases — —

Tax positions taken during a prior yearIncreases 162 125Decreases (157) (230)

Decreases for settlements during the period — (10)Reductions for lapses of applicable statute of limitations — —

Balance at December 31 $ 2,237 $ 2,114

The unrecognized tax benefits in the table above reflect affirmative claims related to timing differences of$1.5 billion and $1.6 billion at December 31, 2008 and 2007, respectively, that have been claimed on amendedtax returns, but have not met the recognition threshold pursuant to FIN 48 and have been denied by the IRS aspart of their examinations. These affirmative claims remain unpaid by the IRS and no receivable has beenrecorded. Edison International has vigorously defended these affirmative claims in IRS administrative appealsproceedings and these claims are included in the ongoing Global Settlement negotiations.

It is reasonably possible that Edison International could resolve, as part of the Global Settlement, or otherwise,with the IRS, all or a portion of the unrecognized tax benefits through tax year 2002 within the next12 months, which could reduce unrecognized tax benefits by up to $1.4 billion.

The total amount of unrecognized tax benefits as of December 31, 2008 and 2007, respectively, that ifrecognized, would have an effective tax rate impact is $210 million and $206 million, respectively.

Accrued Interest and Penalties

The total amounts of accrued interest and penalties related to Edison International’s income tax reserve were$200 million and $162 million as of December 31, 2008 and 2007, respectively. The after-tax interest expense(income) recognized and included in income tax expense was $23 million and $(12) million in 2008 and 2007,respectively.

California Apportionment

In December 2006, Edison International reached a settlement with the California Franchise Tax Boardregarding the sourcing of gross receipts from the sale of electric services for California state taxapportionment purposes for tax years 1981 to 2004. In 2006, Edison International recorded a $49 millionbenefit related to a tax reserve adjustment as a result of this settlement. In the FIN 48 adoption, a $54 millionbenefit was recorded related to this same issue. In addition, Edison International received a net cash refund ofapproximately $52 million in April 2007.

Tax Positions being Addressed as Part of Active Examinations, Administrative Appeals and the GlobalSettlement

In the normal course, Edison International’s federal income tax returns are examined by the IRS and EdisonInternational challenges deficiency adjustments, asserted as part of an examination, to the AdministrativeAppeals branch of the IRS (IRS Appeals) to the extent Edison International believes its tax reporting positionsproperly complied with the relevant tax law and that the IRS’ basis for making such adjustments lacks merit.

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Edison International has challenged certain IRS deficiency adjustments, asserted as part of the examination oftax years 1994 – 1999 with IRS Appeals. Edison International has also been under active IRS examination fortax years 2000 – 2002 and during the third quarter of 2008, the IRS commenced an examination of tax years2003 – 2006. In addition, the statute of limitations remains open for tax years 1986 – 1993, which has allowedEdison International to file certain affirmative claims related to these tax years.

Most of the tax positions that Edison International is addressing with IRS Appeals relate to the timing of whendeductions for federal income tax purposes are allowed to be reflected on filed income tax returns and, assuch, any deductions not sustained would be deductible on future tax returns filed by Edison International.However, any penalties and interest associated with disallowed deductions would result in a permanent cost.Edison International has also filed affirmative claims with respect to certain tax years 1986 through 2005 withthe IRS and state tax authorities. At this time, there has not been a final determination of these affirmativeclaims by the IRS or state tax authorities. Benefits, if any, associated with these affirmative claims would berecorded in accordance with FIN 48 which provides that recognition would occur at the earlier of whenEdison International would make an assessment that the affirmative claim position has a more likely than notprobability of being sustained or when a settlement of the affirmative claim is consummated with the taxauthority. Certain of these affirmative claims have been recognized as part of the implementation of FIN 48.

Edison International has been engaged in settlement negotiations with the IRS to reach a Global Settlementdescribed below of all unresolved tax disputes and affirmative claims for tax years 1986 – 2002 and to resolvecross-border, leveraged-lease issues in their entirety.

In addition to the IRS audits, Edison International’s California and other state income tax returns are, in thenormal course, subjected to examination by the California Franchise Tax Board and the other state taxauthorities. The Franchise Tax Board has substantially completed its examination of all tax years through 2002and is currently awaiting resolution of the IRS audit before finalizing the audit for these tax years. EdisonInternational is currently under active examination for tax years 2003 – 2004 and remains subject toexamination by the California Franchise Tax Board for tax years 2005 and forward.

Edison International filed amended California Franchise tax returns for tax years 1997 – 2002 to mitigate thepossible imposition of California non-economic substance penalty provisions on transactions that may beconsidered as Listed or substantially similar to Listed Transactions described in an IRS notice that waspublished in 2001. These transactions include certain Edison Capital leveraged-lease transactions and an SCEsubsidiary contingent liability company transaction, described below. Edison International filed these amendedreturns under protest retaining its appeal rights.

The issues discussed below are included in the ongoing IRS examination and appeals process and are includedin the scope of issues being addressed as part of the Global Settlement process.

Balancing Account Over-Collections

In response to an affirmative claim filed by Edison International related to balancing account over-collections,the IRS issued a Notice of Proposed Adjustment in July 2007 as part of the ongoing IRS examinations andadministrative appeals processes. The tax years to which adjustments are made pursuant to this Notice ofProposed Adjustment are included in the scope of the Global Settlement process. The cash and earningsimpacts of this position are dependent on the ultimate settlement of all open tax issues, including this issue, inthese tax years. Edison International expects that resolution of this issue could potentially increase earningsand cash flows within the range of $70 million to $80 million and $300 million to $350 million, respectively.

Contingent Liability Company

The IRS has asserted tax deficiencies and penalties of $53 million and $22 million, respectively, for tax years1997 – 1999 with respect to a transaction entered into by a former SCE subsidiary which the IRS has assertedto be substantially similar to a Listed Transaction described by the IRS as a contingent liability company.

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Cross-Border Lease Transactions

As part of a nationwide challenge of cross border lease transactions, the IRS has asserted deficiencies relatedto Edison International’s deferral of income taxes associated with certain of its cross-border, leveraged leases.

These asserted deficiencies relate to Edison Capital’s income tax treatment of both its foreign power plant andelectric locomotive sale/leaseback transactions entered into in 1993 and 1994 (Replacement Leases, which theIRS refers to as sale-in/lease-out or SILOs) and its foreign power plants and electric transmission systemlease/leaseback transactions entered into in 1997 and 1998 (Lease/Leaseback, which the IRS refers to as lease-in/lease-out or LILOs). For tax years 1994 – 1999, Edison International is challenging the asserted deficienciesin ongoing IRS appeals proceedings and is seeking to resolve the asserted deficiencies as part of the GlobalSettlement process.

In 1999, Edison Capital entered into a lease/service contract transaction involving a foreign telecommunicationsystem (Service Contract, which the IRS refers to as a SILO). As part of an ongoing examination of 2000 –2002, the IRS examination branch has been reviewing Edison International’s income tax treatment of thisService Contract. The income tax treatment of the Service Contract is included in the Global Settlementprocess for all tax years.

The following table summarizes estimated federal and state income taxes deferred from these leases as ofDecember 31, 2008. Repayment of the entire amount of the deferred income taxes, as provided in the tablebelow, would be accelerated if Edison International and the IRS were unable to reach a settlement and the IRSposition were sustained in litigation:

In millions

Tax YearsUnder Appeal1994 – 1999

Tax YearsUnder Audit2000 – 2006

UnauditedTax Years

2007 – 2008 Total

Replacement Leases (SILO) $ 44 $ 42 $ 7 $ 93Lease/Leaseback (LILO) 563 572 (32) 1,103Service Contract (SILO) — 326 110 436

Total $ 607 $ 940 $ 85 $ 1,632

As of December 31, 2008, the after-tax interest on the proposed tax adjustments is estimated to beapproximately $643 million. The IRS has also asserted a 20% penalty on any sustained adjustment (other thanwith respect to the Service Contract).

Edison International believes that its maximum earnings exposure related to these leases, measured as ofDecember 31, 2008, is approximately $1.3 billion after taxes, calculated by reclassifying deferred incometaxes to current, re-computing the cumulative earnings under the leases in accordance with lease accountingrules (FASB Staff Position FAS 13-2), and recording interest related to the current income tax liability. Interestwill continue to accrue until the alleged deficiency is resolved. This exposure does not include IRS assertedpenalties of 20%, as Edison International does not believe that even if the tax return positions taken by EdisonCapital are successfully challenged by the IRS that these penalties would be sustained. The current and futureearnings and cash positions of SCE and EME are virtually unaffected by these leases.

During the second quarter of 2008, there were court decisions involving income taxation of cross-borderleveraged leases that were adverse to the taxpayers involved. These developments underscore the uncertainnature of tax conclusions in this area. Despite these developments, Edison International believes it properlyreported these transactions based on applicable statutes, regulations and case law and, in the absence of anysettlement with the IRS, will continue to vigorously defend its tax treatment of these leases. EdisonInternational will continue to monitor and evaluate its lease transactions with respect to future events. Futureadverse developments, including further adverse case law developments, could change Edison International’scurrent conclusions.

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Global Settlement

As previously disclosed, Edison International has negotiated the material terms of a Global Settlement withthe IRS which, if consummated, would resolve cross-border, leveraged lease issues in their entirety and allother outstanding tax disputes for open tax years 1986 through 2002, including certain affirmative claims forunrecognized tax benefits. Consummation of the Global Settlement is subject to review by the Staff of theJoint Committee on Taxation, a committee of the United States Congress (the “Joint Committee”). The IRSsubmitted the pertinent terms of the Global Settlement to the Joint Committee during the fourth quarter of2008, and its response is currently pending. Edison International cannot predict the timing of when the JointCommittee will complete its review. Moreover, Edison International cannot predict whether the JointCommittee will concur with the settlement terms negotiated by the IRS for the Global Settlement issues andwhether any non-concurrence would result in the IRS proposing different settlement terms. Failure toconsummate the Global Settlement and to be successful in any ensuing litigation over issues included in theGlobal Settlement process, including asserted deficiencies regarding the cross-border leases, could have anadverse affect on Edison International.

In the first quarter of 2009, Edison International terminated two of the six cross-border leveraged leases. Thetiming for terminating the remaining cross-border leases is uncertain and could occur prior to the JointCommittee completing its work or otherwise prior to consummation of the settlement. Edison Capital and itssubsidiaries have reached an agreement based on executed term sheets with all of the counterparties to itsSILOs and LILOs which contemplate termination of the leases subject to a final settlement agreement with theIRS. Certain of these agreements are not binding on Edison Capital or the counterparties until suchtermination. Upon termination of the leases, the lessees would be required to make termination payments fromcertain collateral deposits associated with the leases, and Edison International would no longer recognizeearnings from such leases. In 2008 income from leveraged leases was $28 million. If all settlements includedin the Global Settlement process were ultimately concluded consistent with the terms submitted to the JointCommittee, Edison International would expect that the settlement of the disputed lease issues and theresolution of the above-mentioned affirmative claims would result in a portion of any charge initially recordedupon termination of the leases being offset and/or reduced, and the net after-tax earnings charge that wouldremain is currently expected to be less than half of the maximum after-tax earnings exposure, calculated as ofDecember 31, 2008, discussed above. Furthermore, if all settlements included in the Global Settlementdiscussions were ultimately concluded consistent with the terms submitted to the Joint Committee, the netcash impact upon Edison International as a whole of the Global Settlement and lease terminations would bepositive over time. Termination of the leases prior to consummation of the settlements would result in EdisonInternational initially recording an after-tax charge to earnings currently estimated to be at least $650 million(and potentially up to the maximum earnings exposure indicated above), which would be reduced and/or offsetupon completion of the Global Settlement.

To the extent that Edison International is unable to consummate the Global Settlement or other acceptablesettlement with the IRS, Edison International will continue to vigorously defend its tax treatment of the leasesand is prepared to take legal action. If Edison International were to commence litigation in certain forums, itwould need to make payments of the disputed taxes, along with interest and any penalties asserted by the IRS,and thereafter pursue refunds. In the United States Tax Court, no upfront payment would be required. In 2006,Edison International paid $111 million of the taxes, interest and penalties for tax year 1999 followed by arefund claim for the same amount. The IRS did not act on this refund claim within the statutory period, whichprovides Edison International with the option of being able to take legal action to assert its refund claim. Tothe extent an acceptable settlement is not reached with the IRS, Edison International, based on its preferencefor litigation forum, may file refund claims for any taxes, interest and penalties paid for tax years related tothese leases. However, Edison International has not decided whether and to what extent it would makeadditional payments related to later tax years to fund its right to litigate in certain forums should the GlobalSettlement, or another settlement, not be consummated.

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If and when Edison International and the IRS consummate a settlement, Edison International will file amendedtax returns with the Franchise Tax Board and other state administrative agencies, for those states in whichEdison International has an income tax filing requirement, to reflect the respective state income tax impact ofthe settlement terms.

Resolution of Federal and State Income Tax Issues Being Addressed in Ongoing Examinations,Administrative Appeals and the Global Settlement

Edison International continues its efforts to resolve open tax issues through tax year 2002 as part of the GlobalSettlement. Although the timing for resolving these open tax positions is uncertain, it is reasonably possiblethat all or a significant portion of these open tax issues through tax year 2002 could be resolved within thenext 12 months.

Note 5. Compensation and Benefit Plans

Employee Savings Plan

Edison International has a 401(k) defined contribution savings plan designed to supplement employees’retirement income. The plan received employer contributions of $80 million in 2008, $73 million in 2007 and$69 million in 2006.

Pension Plans and Postretirement Benefits Other Than Pensions

SFAS No. 158 requires companies to recognize the overfunded or underfunded status of defined benefitpension and other postretirement plans as assets and liabilities in the balance sheet; the assets and/or liabilitiesare normally offset through other comprehensive income (loss). Edison International adopted SFAS No. 158 asof December 31, 2006. In accordance with SFAS No. 71, Edison International recorded regulatory assets andliabilities instead of charges and credits to other comprehensive income (loss) for its postretirement benefitplans that are recoverable in utility rates.

Pension Plans

Noncontributory defined benefit pension plans (some with cash balance features) cover most employeesmeeting minimum service requirements. SCE recognizes pension expense for its nonexecutive plan ascalculated by the actuarial method used for ratemaking. The expected contributions (all by the employer) areapproximately $51 million for the year ending December 31, 2009. The fair value of plan assets is determinedprimarily by quoted market prices.

Volatile market conditions have affected the value of Edison International’s trusts established to fund its futurelong-term pension benefits. The market value of the investments (reflecting investment returns, contributionsand benefit payments) within the plan trusts declined 35% during 2008. This reduction in the value of planassets resulted in a change in the pension plan funding status from overfunded to underfunded and will alsoresult in increased future expense and increased future contributions. Changes in the plan’s funded status affectthe assets and liabilities recorded on the balance sheet in accordance with SFAS No. 158. Due to SCE’sregulatory recovery treatment, the recognition of the funded status is offset by regulatory liabilities and assets.In the 2009 GRC, SCE requested recovery of and continued balancing account treatment for amountscontributed to these trusts. The Pension Protection Act of 2006 establishes new minimum funding standardsand restricts plans underfunded by more than 20% from providing lump sum distributions and adoptingamendments that increase plan liabilities.

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Information on plan assets and benefit obligations is shown below:

In millions Year ended December 31, 2008 2007

Change in projected benefit obligationProjected benefit obligation at beginning of year $ 3,355 $ 3,410Service cost 120 117Interest cost 199 185Amendments — (5)Actuarial loss (gain) 3 (97)Special termination benefits — 2Benefits paid (238) (257)

Projected benefit obligation at end of year $ 3,439 $ 3,355

Change in plan assetsFair value of plan assets at beginning of year $ 3,597 $ 3,458Actual return (loss) on plan assets (1,105) 294Employer contributions 86 102Benefits paid (238) (257)

Fair value of plan assets at end of year $ 2,340 $ 3,597

Funded status at end of year $ (1,099) $ 242

Amounts recognized in the consolidated balance sheets consist of :Long-term assets $ — $ 430Current liabilities (9) (8)Long-term liabilities (1,090) (180)

$ (1,099) $ 242

Amounts recognized in accumulated other comprehensive loss consist of:Prior service cost $ 2 $ 3Net loss 91 37

$ 93 $ 40

Amounts recognized as a regulatory asset (liability):Prior service cost $ 33 $ 49Net loss (gain) 951 (357)

$ 984 $ 308

Total not yet recognized as expense $ 1,077 $ 348

Accumulated benefit obligation at end of year $ 3,129 $ 2,992Pension plans with an accumulated benefit obligation in excess of plan assets:Projected benefit obligation $ 3,439 $ 276Accumulated benefit obligation $ 3,129 $ 232Fair value of plan assets $ 2,340 $ 88Weighted-average assumptions used to determine obligations at end of year:Discount rate 6.25% 6.25%Rate of compensation increase 5.0% 5.0%

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Expense components and other amounts recognized in other comprehensive income:

Expense components are:


Service cost $ 120 $ 117 $ 118Interest cost 199 185 181Expected return on plan assets (259) (245) (232)Special termination benefits — 2 8Amortization of prior service cost 17 17 16Amortization of net loss 5 6 6

Expense under accounting standards $ 82 $ 82 $ 97Regulatory adjustment – deferred (4) (3) (10)

Total expense recognized $ 78 $ 79 $ 87

Other changes in plan assets and benefit obligations recognized in other comprehensive income:


Net loss $ 59 $ —Prior service cost — —Amortization of prior service cost (1) (1)Amortization of net loss (5) (6)

Total recognized in other comprehensive (income) loss $ 53 $ (7)

Total recognized in expense and other comprehensive income $ 131 $ 72

Effective with the adoption of SFAS No. 158, as of December 31, 2006, and in accordance with SFAS No. 71,Edison International records regulatory assets and liabilities instead of charges and credits to othercomprehensive income (loss) for its postretirement benefit plans that are recoverable in utility rates. Theestimated amortization amounts for 2009 are $17 million for prior service cost and $57 million for net lossincluding $1 million and $9 million respectively, reclassified from other comprehensive income.

Due to the Mohave shutdown, SCE has incurred costs for special termination benefits.

The following are weighted-average assumptions used to determine expense:


Discount rate 6.25% 5.75% 5.5%Rate of compensation increase 5.0% 5.0% 5.0%Expected long-term return on plan assets 7.5% 7.5% 7.5%

The following benefit payments, which reflect expected future service, are expected to be paid:

In millions Year ended December 31,

2009 $ 2912010 $ 2972011 $ 3122012 $ 3192013 $ 3162014 – 2018 $ 1,576

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The following are asset allocations by investment category:

Target for2009 2008 2007

December 31,

United States equities 39% 41% 47%Non-United States equities 17% 22% 25%Private equities 4% 4% 2%Fixed income 40% 33% 26%

Postretirement Benefits Other Than Pensions

Most nonunion employees retiring at or after age 55 with at least 10 years of service are eligible forpostretirement health and dental care, life insurance and other benefits. Eligibility depends on a number offactors, including the employee’s hire date. The expected contributions (all by the employer) to the PBOP trustare $128 million for the year ending December 31, 2009. The fair value of plan assets is determined primarilyby quoted market prices.

Volatile market conditions have affected the value of Edison International’s trusts established to fund its futureother postretirement benefits. The market value of the investments (reflecting investment returns, contributionsand benefit payments) within the plan trust declined 33% during 2008. This reduction in the value of planassets resulted in an increase in the plan underfunded status and will also result in increased future expenseand increased future contributions. Changes in the plan’s funded status affect the assets and liabilities recordedon the balance sheet in accordance with SFAS No. 158. Due to SCE’s regulatory recovery treatment, therecognition of the funded status is offset by regulatory liabilities and assets. In the 2009 GRC, SCE requestedrecovery of and continued balancing account treatment for amounts contributed to this trust.

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Information on plan assets and benefit obligations is shown below:


Change in benefit obligationBenefit obligation at beginning of year $ 2,271 $ 2,260Service cost 41 45Interest cost 136 130Amendments 3 7Actuarial gain (20) (77)Special termination benefits — 1Plan participants’ contributions 11 9Medicare Part D subsidy received 5 4Benefits paid (96) (108)

Benefit obligation at end of year $ 2,351 $ 2,271

Change in plan assetsFair value of plan assets at beginning of year $ 1,816 $ 1,743Actual return (loss) on assets (557) 117Employer contributions 33 51Plan participants’ contributions 11 9Medicare Part D subsidy received 5 4Benefits paid (96) (108)

Fair value of plan assets at end of year $ 1,212 $ 1,816

Funded status at end of year $ (1,139) $ (455)

Amounts recognized in the consolidated balance sheets consist of:Current liabilities $ (20) $ (20)Long-term liabilities (1,119) (435)

$ (1,139) $ (455)

Amounts recognized in accumulated other comprehensive loss (income)consist of:

Prior service cost (credit) $ (4) $ (9)Net loss 24 20

$ 20 $ 11

Amounts recognized as a regulatory asset (liability):Prior service cost (credit) $ (178) $ (206)Net loss 1,076 437

$ 898 $ 231

Total not yet recognized as expense $ 918 $ 242

Weighted-average assumptions used to determine obligations at end of year:Discount rate 6.25% 6.25%Assumed health care cost trend rates:Rate assumed for following year 8.75% 9.25%Ultimate rate 5.5% 5.0%Year ultimate rate reached 2016 2015

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Expense components and other amounts recognized in other comprehensive income:

Expense components are:


Service cost $ 41 $ 45 $ 45Interest cost 136 130 120Expected return on plan assets (123) (118) (105)Special termination benefits — 1 4Amortization of prior service cost (credit) (31) (31) (31)Amortization of net loss 16 30 43

Total expense $ 39 $ 57 $ 76

Other changes in plan assets and benefit obligations recognized in other comprehensive income:


Net loss $ 6 $ 3Prior service cost 3 —Amortization of prior service cost (credit) 2 2Amortization of net loss (2) (2)

Total recognized in other comprehensive income $ 9 $ 3

Total recognized in expense and other comprehensive income $ 48 $ 60

Effective with the adoption of SFAS No. 158, as of December 31, 2006, and in accordance with SFAS No. 71,Edison International records regulatory assets and liabilities instead of charges and credits to othercomprehensive income (loss) for its postretirement benefit plans that are recoverable in utility rates. Theestimated amortization amounts for 2009 are $(30) million for prior service cost (credit) and $63 million fornet loss including $(2) million and $1 million respectively, reclassified from other comprehensive income.

Due to the Mohave shutdown, SCE has incurred costs for special termination benefits.

The following are weighted-average assumptions used to determine expense:


Discount rate 6.25% 5.75% 5.5%Expected long-term return on plan assets 7.0% 7.0% 7.0%Assumed health care cost trend rates:Current year 9.25% 9.25% 10.25%Ultimate rate 5.0% 5.0% 5.0%Year ultimate rate reached 2015 2015 2011

Increasing the health care cost trend rate by one percentage point would increase the accumulated benefitobligation as of December 31, 2008 by $263 million and annual aggregate service and interest costs by$18 million. Decreasing the health care cost trend rate by one percentage point would decrease theaccumulated benefit obligation as of December 31, 2008 by $236 million and annual aggregate service andinterest costs by $16 million.

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The following are benefit payments expected to be paid:

In millions Year ending December 31,Before

Subsidy* Net

2009 $ 104 $ 992010 $ 115 $ 1092011 $ 125 $ 1192012 $ 135 $ 1272013 $ 144 $ 1362014 – 2018 $ 857 $ 801

* Medicare Part D prescription drug benefits

The following are asset allocations by investment category:

Target for2009 2008 2007

December 31,

United States equities 45% 58% 62%Non-United States equities 17% 11% 14%Private equities 1% — —Fixed income 37% 31% 24%

Description of Pension and Postretirement Benefits Other Than Pensions Investment Strategies

The investment of plan assets is overseen by a fiduciary investment committee. Plan assets are invested usinga combination of asset classes, and may have active and passive investment strategies within asset classes. Asa result of the significant increase in global financial markets volatility, during 2008 and in early 2009, thetrusts’ investment committee approved interim changes in target asset allocations. Edison Internationalemploys multiple investment management firms. Investment managers within each asset class cover a range ofinvestment styles and approaches. Risk is managed through diversification among multiple asset classes,managers, styles and securities. Plan, asset class and individual manager performance is measured againsttargets. Edison International also monitors the stability of its investments managers’ organizations.

Allowable investment types include:

United States Equities: Common and preferred stocks of large, medium, and small companies which arepredominantly United States-based.

Non-United States Equities: Equity securities issued by companies domiciled outside the United States and indepository receipts which represent ownership of securities of non-United States companies.

Private Equity: Limited partnerships that invest in nonpublicly traded entities.

Fixed Income: Fixed income securities issued or guaranteed by the United States government, non-UnitedStates governments, government agencies and instrumentalities, mortgage backed securities and corporate debtobligations. A small portion of the fixed income positions may be held in debt securities that are belowinvestment grade.

Permitted ranges around asset class portfolio weights are plus or minus 3%. Where approved by the fiduciaryinvestment committee, futures contracts are used for portfolio rebalancing and to approach fully investedportfolio positions. Where authorized, a few of the plan’s investment managers employ limited use ofderivatives, including futures contracts, options, options on futures and interest rate swaps in place of directinvestment in securities to gain efficient exposure to markets. Derivatives are not used to leverage the plans orany portfolios.

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Determination of the Expected Long-Term Rate of Return on Assets

The overall expected long term rate of return on assets assumption is based on the long-term target assetallocation for plan assets and capital markets return forecasts for asset classes employed. A portion of thePBOP trust asset returns are subject to taxation, so the expected long-term rate of return for these assets isdetermined on an after-tax basis.

Capital Markets Return Forecasts

Capital markets return forecasts are based on a long-term equilibrium forecast from an independent firm, aswell as a separate analysis of expected equilibrium returns. The independent firm uses its research andjudgment to determine long-term equilibrium forecasts. A core set of macroeconomic variables is usedincluding real GDP growth, personal consumption expenditures, the federal funds target rate, dividend yield,and the Treasury yield curve. Fixed income, equity and private equity returns are determined from thesefactors. In addition, a separate analysis of equilibrium returns is made. The estimated total return for fixedincome is based on an equilibrium yield for intermediate United States government bonds plus a premium forexposure to non-government bonds in the broad fixed income market. The equilibrium yield is based onanalysis of historic and projected data and is consistent with experience over various economic environments.The premium of the broad market over United States government bonds is a historic average premium. Theestimated rate of return for equity includes a 3% premium over the estimated total return of intermediateUnited States government bonds. The rate of return for private equity is estimated to be a 5% premium overpublic equity, reflecting a premium for higher volatility and illiquidity.

Stock-Based Compensation

Total stock-based compensation expense, net of amounts capitalized (reflected in the caption “Other operationand maintenance” on the consolidated statements of income) was $31 million, $42 million and $52 million for2008, 2007 and 2006, respectively. The income tax benefit recognized in the consolidated statements ofincome was $12 million, $17 million and $21 million for 2008, 2007 and 2006, respectively. Total stock-basedcompensation cost capitalized was $3 million, $4 million and $6 million for 2008, 2007 and 2006,respectively.

Stock Options

Under various plans, Edison International has granted stock options at exercise prices equal to the average ofthe high and low price, and beginning in 2007, at the closing price at the grant date. Edison International maygrant stock options and other awards related to or with a value derived from its common stock to directors andcertain employees. Options generally expire 10 years after the grant date and vest over a period of four yearsof continuous service, with expense recognized evenly over the requisite service period, except for awardsgranted to retirement-eligible participants, as discussed in “Stock-Based Compensation” in Note 1. Stock-based compensation expense, net of amounts capitalized, associated with stock options was $25 million,$25 million and $37 million for 2008, 2007 and 2006, respectively. See “Stock-Based Compensation” inNote 1 for further discussion.

Stock options granted in 2003 through 2006 accrue dividend equivalents for the first five years of the optionterm. Stock options granted in 2007 and 2008 have no dividend equivalent rights. Unless transferred tononqualified deferral plan accounts, dividend equivalents accumulate without interest. Dividend equivalents arepaid only on options that vest, including options that are unexercised. Dividend equivalents are paid in cashafter the vesting date. Edison International has discretion to pay certain dividend equivalents in shares ofEdison International common stock. Additionally, Edison International will substitute cash awards to theextent necessary to pay tax withholding or any government levies.

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The fair value for each option granted was determined as of the grant date using the Black-Scholes option-pricing model. The Black-Scholes option-pricing model requires various assumptions noted in the followingtable.


Expected terms (in years) 7.4 7.5 9 to 10Risk-free interest rate 2.6% – 3.8% 4.6% – 4.8% 4.3% – 4.7%Expected dividend yield 2.3% – 3.9% 2.1% – 2.4% 2.3% – 2.8%Weighted-average expected dividend yield 2.6% 2.4% 2.4%Expected volatility 17% – 19% 16% – 17% 16% – 17%Weighted-average volatility 17.6% 16.5% 16.3%

The expected term represents the period of time for which the options are expected to be outstanding and isprimarily based on historical exercise and post-vesting cancellation experience and stock price history. Therisk-free interest rate for periods within the contractual life of the option is based on a zero couponU.S. Treasury issued STRIPS (separate trading of registered interest and principal of securities) whosematurity equals the option’s expected term on the measurement date. In 2006 – 2008, expected volatility isbased on the historical volatility of Edison International’s common stock for the most recent 36 months.

The following is a summary of the status of Edison International stock options:

StockOptions

ExercisePrice

RemainingContractual

Term(Years)

AggregateIntrinsic

Value

Weighted-Average

Outstanding at December 31, 2007 12,105,642 $ 30.55Granted 2,843,308 $ 48.43Expired (13,905) $ 46.65Forfeited (343,423) $ 48.43Exercised (1,149,787) $ 26.14

Outstanding at December 31, 2008 13,441,835 $ 34.22 6.27

Vested and expected to vest at December 31, 2008 13,045,138 $ 33.87 6.20 $ 156,019,850

Exercisable at December 31, 2008 7,988,722 $ 26.79 5.08 $ 152,105,267

Stock options granted in 2008 and 2007 do not accrue dividend equivalents except for options granted toEdison International’s Board of Directors.

The weighted-average grant-date fair value of options granted during 2008, 2007 and 2006 was $9.70, $11.44and $14.42, respectively. The total intrinsic value of options exercised during 2008, 2007 and 2006 was$24 million, $109 million, and $70 million, respectively. At December 31, 2008, there was $29 million of totalunrecognized compensation cost related to stock options, net of expected forfeitures. That cost is expected tobe recognized over a weighted-average period of approximately two years. The fair value of options vestedduring 2008, 2007 and 2006 was $24 million, $27 million and $45 million, respectively.

The amount of cash used to settle stock options exercised was $55 million, $195 million and $136 million for2008, 2007 and 2006, respectively. Cash received from options exercised for 2008, 2007 and 2006 was$30 million, $86 million and $66 million, respectively. The estimated tax benefit from options exercised for2008, 2007 and 2006 was $10 million, $43 million and $27 million, respectively.

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Performance Shares

A target number of contingent performance shares were awarded to executives in March 2006, March 2007and March 2008 and vest at the end of December 2008, 2009 and 2010, respectively. Performance sharesawarded in 2005 and 2006 accrue dividend equivalents which accumulate without interest and will be payablein cash following the end of the performance period when the performance shares are paid. EdisonInternational has discretion to pay certain dividend equivalents in Edison International common stock.Performance shares awarded in 2007 and 2008 contain dividend equivalent reinvestment rights. An additionalnumber of target contingent performance shares will be credited based on dividends on Edison Internationalcommon stock for which the ex-dividend date falls within the performance period. The vesting of EdisonInternational’s performance shares is dependent upon a market condition and three years of continuous servicesubject to a prorated adjustment for employees who are terminated under certain circumstances or retire, butpayment cannot be accelerated. The market condition is based on Edison International’s common stockperformance relative to the performance of a specified group of companies at the end of a three-calendar-yearperiod. The number of performance shares earned is determined based on Edison International’s rankingamong these companies. Dividend equivalents will be adjusted to correlate to the actual number ofperformance shares paid. Performance shares earned are settled half in cash and half in common stock;however, Edison International has discretion under certain of the awards to pay the half subject to cashsettlement in common stock. Additionally, cash awards are substituted to the extent necessary to pay taxwithholding or any government levies. The portion of performance shares settled in cash is classified as ashare-based liability award. The fair value of these shares is remeasured at each reporting period and therelated compensation expense is adjusted. The portion of performance shares payable in common stock isclassified as a share-based equity award. Compensation expense related to these shares is based on the grant-date fair value. Performance shares expense is recognized ratably over the requisite service period based onthe fair values determined, except for awards granted to retirement-eligible participants, as discussed in“Stock-Based Compensation” in Note 1. Stock-based compensation expense (benefit), net of amountscapitalized, associated with performance shares was $(4) million, $12 million and $15 million for 2008, 2007and 2006, respectively. The amount of cash used to settle performance shares classified as equity awards was$10 million, $20 million and $37 million for 2008, 2007 and 2006, respectively. In 2007 we changed theclassification of the cash paid for the settlements of performance shares from common stock to retainedearnings to conform with the classification for settlements of stock option exercises.

The performance shares’ fair value is determined using a Monte Carlo simulation valuation model. The MonteCarlo simulation valuation model requires a risk-free interest rate and an expected volatility rate assumption.The risk-free interest rate is based on a 52-week historical average of the three-year zero couponU.S. Treasury issued STRIPS (separate trading of registered interest and principal of securities) and is used asa proxy for the expected return for the specified group of companies. Volatility is based on the historicalvolatility of Edison International’s common stock for the recent 36 months. Historical volatility for eachcompany in the specified group is obtained from a financial data services provider.

Edison International’s risk-free interest rate used to determine the grant date fair values for the 2008, 2007 and2006 performance shares classified as share-based equity awards was 3.9%, 4.8% and 4.1%, respectively.Edison International’s expected volatility used to determine the grant date fair values for the 2008, 2007 and2006 performance shares classified as share-based equity awards was 17.4%, 16.5% and 16.2%, respectively.The portion of performance shares classified as share-based liability awards are revalued at each reportingperiod. The risk-free interest rate and expected volatility rate used to determine the fair value as ofDecember 31, 2008 was 0.8% and 19.2%, respectively, for 2008 performance shares. The risk-free interest rateand expected volatility rate used to determine the fair value as of December 31, 2007 was 4.3% and 17.1%,respectively, for 2007 performance shares.

The total intrinsic value of performance shares settled during 2008, 2007 and 2006 was $22 million,$44 million and $73 million, respectively, which included cash paid to settle the performance shares classified

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as liability awards for 2008, 2007 and 2006 of $8 million, $14 million and $24 million, respectively. AtDecember 31, 2008, there was $4 million (based on the December 31, 2008 fair value of performance sharesclassified as liability awards) of total unrecognized compensation cost related to performance shares. That costis expected to be recognized over a weighted-average period of approximately two years. The fair value ofperformance shares vested during 2008, 2007 and 2006 was $4 million, $17 million and $27 million,respectively.

The following is a summary of the status of Edison International nonvested performance shares classified asequity awards:

PerformanceShares

Weighted-AverageGrant-DateFair Value

Nonvested at December 31, 2007 149,499 $ 55.01Granted 117,075 $ 45.53Forfeited (91,397) $ 53.53Paid out — $ —

Nonvested at December 31, 2008 175,177 $ 49.45

The weighted-average grant-date fair value of performance shares classified as equity awards granted during2008, 2007 and 2006 was $45.53, $57.55 and $52.90, respectively.

The following is a summary of the status of Edison International nonvested performance shares classified asliability awards (the current portion is reflected in the caption “Other current liabilities” and the long-termportion is reflected in “Accumulated provision for pensions and benefits” on the consolidated balance sheets):

PerformanceShares

Weighted-AverageFair Value

Nonvested at December 31, 2007 149,680Granted 116,894Forfeited (91,397)Paid out —

Nonvested at December 31, 2008 175,177 $ 3.74

Note 6. Commitments and Contingencies

Lease Commitments

In accordance with EITF No. 01-8, power contracts signed or modified after June 30, 2003, need to beassessed for lease accounting requirements. Unit specific contracts in which SCE takes virtually all of theoutput of a facility are generally considered to be leases. As of December 31, 2005, SCE had six powercontracts classified as operating leases. In 2006, SCE modified 62 power contracts. No contracts weremodified in 2007 and 2008. The modifications to the contracts resulted in a change to the contractual terms ofthe contracts at which time SCE reassessed these power contracts under EITF No. 01-8 and determined thatthe contracts are leases and subsequently met the requirements for operating leases under SFAS No. 13. Thesepower contracts had previously been grandfathered relative to EITF No. 01-8 and did not meet the normalpurchases and sales exception. As a result, these contracts were recorded on the consolidated balance sheets atfair value in accordance with SFAS No. 133. Due to regulatory mechanisms, fair value changes did not affectearnings. At the time of modification, SCE had assets and liabilities related to mark-to-market gains or losses.Under SFAS No. 133, the assets and liabilities were reclassified to a lease prepayment or accrual and wereincluded in the cost basis of the lease. The lease prepayment and accruals are being amortized over the life ofthe lease on a straight-line basis. At December 31, 2008, the net liability was $64 million. At December 31,2008, SCE had 69 power contracts classified as operating leases. Operating lease expense for power purchases

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was $328 million in 2008, $297 million in 2007, and $188 million in 2006. In addition, as of December 31,2008, SCE had four power purchase contracts which met the requirements for capital leases. These capitalleases have a net commitment of $1.22 billion at December 31, 2008 and $20 million at December 31, 2007.SCE’s total estimated capital lease executory costs and interest expense were $1.71 billion at December 31,2008 and $20 million at December 31, 2007.

On December 7, 2001, a subsidiary of EME completed a sale-leaseback of EME’s Homer City facilities tothird-party lessors for an aggregate purchase price of $1.6 billion, consisting of $782 million in cash andassumption of debt (the fair value of which was $809 million). Under the terms of the 33.67-year leases,EME’s subsidiary is obligated to make semi-annual lease payments on each April 1 and October 1. If a lessorintends to sell its interest in the Homer City facilities, EME has a right of first refusal to acquire the interest atfair market value. Minimum lease payments (included in the table above) are $151 million in 2009,$155 million in 2010, $160 million in both 2011 and 2012, and $149 million in 2013, and the total remainingminimum lease payments are $1.5 billion. The gain on the sale of the facilities has been deferred and is beingamortized over the term of the leases.

On August 24, 2000, a subsidiary of EME completed a sale-leaseback of EME’s Powerton and Joliet powerfacilities located in Illinois to third-party lessors for an aggregate purchase price of $1.4 billion. Under theterms of the leases (33.75 years for Powerton and 30 years for Joliet), EME’s subsidiary makes semi-annuallease payments on each January 2 and July 2, which began January 2, 2001. EME guarantees its subsidiary’spayments under the leases. If a lessor intends to sell its interest in the Powerton or Joliet power facility, EMEhas a right of first refusal to acquire the interest at fair market value. Minimum lease payments (included inthe table above) are $185 million in 2009, $170 million in 2010, and $151 million in each 2011, 2012 and2013, and the total remaining minimum lease payments are $489 million. The gain on the sale of the powerfacilities has been deferred and is being amortized over the term of the leases.

Under the terms of the foregoing sale-leaseback transactions, distributions are restricted by EME’s subsidiariesunless specified financial covenants are met. At December 31, 2008, EME’s subsidiaries met these covenants.In addition, the lease agreements and the Midwest Generation credit agreement contain covenants that include,among other things, restrictions on the ability of these subsidiaries to incur debt, create liens on its property,merge or consolidate, sell assets, make investments, engage in transactions with affiliates, make distributions,make capital expenditures, enter into agreements restricting its ability to make distributions, engage in otherlines of business or engage in transactions for any speculative purpose.

Edison International has other operating leases for office space, vehicles, property and other equipment (withvarying terms, provisions and expiration dates). The following are estimated remaining commitments (themajority of other operating leases are related to EME’s long-term leases for the Illinois power facilities andHomer City facilities discussed above) for noncancelable operating leases:

In millions Year ending December 31,Power ContractsOperating Leases

OtherOperating Leases

2009 $ 638 $ 1,0512010 625 1,0232011 458 8312012 355 7192013 349 701Thereafter 2,000 4,161

Total $ 4,425 $ 8,486

The minimum commitments above do not include EME’s contingent rentals with respect to the wind projectswhich may be paid under certain leases on the basis of a percentage of sales calculation if this is in excess ofthe stipulated minimum amount.

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As discussed above, SCE modified numerous power contracts which increased the noncancelable operatinglease future commitments and decreased the power purchase commitments below in “Other Commitments.”

Operating lease expense was $583 million in 2008, $539 million in 2007 and $420 million in 2006.

Nuclear Decommissioning Commitment

SCE has collected in rates amounts for the future costs of removal of its nuclear assets, and has placed thoseamounts in independent trusts. The fair value of decommissioning SCE’s nuclear power facilities is$2.9 billion as of December 31, 2008, based on site-specific studies performed in 2005 for San Onofre andPalo Verde. Changes in the estimated costs, timing of decommissioning, or the assumptions underlying theseestimates could cause material revisions to the estimated total cost to decommission. SCE estimates that it willspend approximately $11.5 billion through 2049 to decommission its active nuclear facilities. This estimate isbased on SCE’s decommissioning cost methodology used for rate-making purposes, escalated at rates rangingfrom 1.7% to 7.5% (depending on the cost element) annually. These costs are expected to be funded fromindependent decommissioning trusts, which currently receive contributions of approximately $46 million peryear. SCE estimates annual after-tax earnings on the decommissioning funds of 4.4% to 5.8%. If the assumedreturn on trust assets is not earned, it is probable that additional funds needed for decommissioning will berecoverable through rates in the future. If the assumed return on trust assets is greater than estimated, fundingamounts may be reduced through future decommissioning proceedings.

Decommissioning of San Onofre Unit 1 is underway and will be completed in three phases:(1) decontamination and dismantling of all structures and some foundations; (2) spent fuel storage monitoring;and (3) fuel storage facility dismantling, removal of remaining foundations, and site restoration. Phase one wasscheduled to continue through 2008. Phase two is expected to continue until 2026. Phase three will beconducted concurrently with the San Onofre Units 2 and 3 decommissioning projects. In February 2004, SCEannounced that it discontinued plans to ship the San Onofre Unit 1 reactor pressure vessel to a disposal siteuntil such time as appropriate arrangements are made for its permanent disposal. It will continue to be storedat its current location at San Onofre Unit 1. This action results in placing the disposal of the reactor pressurevessel in Phase three of the San Onofre Unit 1 decommissioning project.

All of SCE’s San Onofre Unit 1 decommissioning costs will be paid from its nuclear decommissioning trustfunds and are subject to CPUC review. The estimated remaining cost to decommission San Onofre Unit 1 isrecorded as an ARO liability ($59 million at December 31, 2008). Total expenditures for the decommissioningof San Onofre Unit 1 were $583 million from the beginning of the project in 1998 through December 31,2008.

Decommissioning expense under the rate-making method was $46 million, $46 million and $32 million in2008, 2007 and 2006, respectively. The ARO for decommissioning SCE’s active nuclear facilities was$2.9 billion and $2.7 billion at December 31, 2008 and 2007, respectively.

See “Nuclear Decommissioning Trusts” in Note 10 for discussion on fair value of the trusts.

Other Commitments

SCE has fuel supply contracts which require payment only if the fuel is made available for purchase. SCE hasa coal fuel contract that requires payment of certain fixed charges whether or not coal is delivered.

SCE has power purchase contracts with certain QFs (cogenerators and small power producers) and otherpower producers. These contracts provide for capacity payments if a facility meets certain performanceobligations and energy payments based on actual power supplied to SCE (the energy payments are notincluded in the table below). There are no requirements to make debt-service payments. In an effort to replacehigher-cost contract payments with lower-cost replacement power, SCE has entered into power purchase

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settlements to end its contract obligations with certain QFs. The settlements are reported as power purchasecontracts on the consolidated balance sheets.

Certain commitments for the years 2009 through 2013 are estimated below:

In millions 2009 2010 2011 2012 2013

Fuel supply $ 667 $ 278 $ 173 $ 202 $ 192Gas and coal transportation payments $ 244 $ 168 $ 7 $ 8 $ 7Purchased power $ 289 $ 368 $ 519 $ 681 $ 660

SCE has an unconditional purchase obligation for firm transmission service from another utility. Minimumpayments are based, in part, on the debt-service requirements of the transmission service provider, whether ornot the transmission line is operable. The contract requires minimum payments of $60 million through 2016(approximately $7 million per year).

At December 31, 2008, EME’s subsidiaries had firm commitments to spend approximately $150 million in2009 on capital and construction expenditures. The majority of these expenditures primarily relate to theconstruction of wind projects and environmental improvements at the Illinois Plants. These expenditures areplanned to be financed by cash on hand and cash generated from operations.

EME had entered into various turbine supply agreements with vendors to support its wind development efforts.At December 31, 2008, EME had secured 484 wind turbines (942 MW) for use in future projects for anaggregate purchase price of $1.2 billion, with remaining commitments of $706 million in 2009 and$232 million in 2010. One of EME’s turbine suppliers has requested an escalation adjustment to its pricing for2008 and 2009 turbines pursuant to its turbine supply agreement. EME is evaluating the request, anddiscussions with the supplier are ongoing. At December 31, 2008 and 2007, EME had recorded wind turbinedeposits of $327 million and $273 million, respectively, included in other long-term assets on its consolidatedbalance sheet. Under certain of these agreements, EME may terminate the purchase of individual turbines, orgroups of turbines, for convenience. Upon any such termination, EME may be obligated to pay terminationcharges to the vendor.

In 2008, EME had entered into an agreement to purchase 5 gas-fired turbines (479 MW) for use in the WalnutCreek project. During the fourth quarter of 2008, EME and its subsidiary terminated the turbine supplyagreement for the project to preserve capital and recorded a pre-tax charge of $23 million ($14 million, aftertax) reflected in “Contract buyout/termination and other” on Edison International’s consolidated statements ofincome. EME plans to purchase turbines for the project subject to resolution of uncertainty regarding theavailability of required emission credits.

At December 31, 2008, Midwest Generation and EME Homer City had fuel purchase commitments with variousthird-party suppliers. Based on the contract provisions, which consist of fixed prices, subject to adjustmentclauses, these minimum commitments are currently estimated to aggregate $638 million in the next four yearssummarized as follows: 2009 – $460 million; 2010 – $160; 2011 – $14 million; and 2012 – $4 million.

In connection with the acquisition of the Illinois Plants, Midwest Generation had assumed a long-term coalsupply contract and recorded a liability to reflect the fair value of this contract. In March 2008, MidwestGeneration entered into an agreement to buy out its coal obligations for the years 2009 through 2012 underthis contract with a one-time payment to be made in January 2009. Midwest Generation recorded a pre-taxgain of $15 million ($9 million, after tax) during the first quarter of 2008 reflected in “Contract buyout/termination and other” on Edison International’s consolidated statements of income.

At December 31, 2008, EME had a contractual commitment to transport natural gas. EME’s share of thecommitment to pay minimum fees under its gas transportation agreement, which has a remaining contractlength of nine years, is currently estimated to aggregate $40 million in the next five years, $8 million each

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year, 2009 through 2013. EME has entered into agreements to re-sell the transportation under this agreementwhich aggregates $50 million over the same period.

At December 31, 2008, Midwest Generation had contractual commitments for the transport of coal to theirrespective facilities. Midwest Generation’s primary contract is with Union Pacific Railroad (and variousdelivering carriers) which extends through 2011. Midwest Generation commitments under this agreement arebased on actual coal purchases from the PRB. Accordingly, Midwest Generation’s contractual obligations fortransportation are based on coal volumes set forth in its fuel supply contracts. Based on the committed coalvolumes in the fuel supply contracts described above, these minimum commitments are currently estimated toaggregate $396 million in the next two years, summarized as follows: 2009 – $236 million and2010 – $160 million.

At December 31, 2008, EME and its subsidiaries were party to a long-term power purchase contract, a coalcleaning agreement, turbine operations and maintenance agreements, and agreements for the purchase oflimestone, ammonia and materials for environmental controls equipment. These minimum commitments arecurrently estimated to aggregate $286 million in the next five years: 2009 – $59 million; 2010 – $78 million;2011 – $67 million; 2012 – $56 million; and 2013 – $26 million.

Guarantees and Indemnities

Edison International’s subsidiaries have various financial and performance guarantees and indemnificationswhich are issued in the normal course of business. As discussed below, these contracts included performanceguarantees, guarantees of debt and indemnifications.

Tax Indemnity Agreements

In connection with the sale-leaseback transactions related to the Homer City facilities in Pennsylvania, thePowerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of itssubsidiaries entered into tax indemnity agreements. Although the Collins Station lease terminated in April2004, Midwest Generation’s tax indemnity agreement with the former lease equity investor is still in effect.Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leasebacktransactions for specified adverse tax consequences that could result in certain situations set forth in each taxindemnity agreement, including specified defaults under the respective leases. The potential indemnityobligations under these tax indemnity agreements could be significant. Due to the nature of these potentialobligations, EME cannot determine a maximum potential liability which would be triggered by a valid claimfrom the lessors. EME has not recorded a liability related to these indemnities.

Indemnities Provided as Part of the Acquisition of the Illinois Plants

In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edisonwith respect to specified environmental liabilities before and after December 15, 1999, the date of sale. Theindemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and aresubject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to anysuch indemnification claim. Due to the nature of the obligation under this indemnity, a maximum potentialliability cannot be determined. This indemnification for environmental liabilities is not limited in term andwould be triggered by a valid claim from Commonwealth Edison. Commonwealth Edison has advised EMEthat Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses thatit may be required to bear as a result of the NOV discussed below under “— Contingencies — MidwestGeneration New Source Review Notice of Violation” and potential litigation by private groups related to theNOV. Except as discussed below, EME has not recorded a liability related to this indemnity.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and ExelonGeneration on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation

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for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under thissupplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and ExelonGeneration for 50% of specific asbestos claims pending as of February 2003 and related expenses lessrecovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated withfuture asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison andMidwest Generation apportion responsibility for future asbestos-related claims based upon the number ofexposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligationsunder this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of eitherparty to terminate); pursuant to the automatic renewal provision, it has been extended until February 2010.There were approximately 222 cases for which Midwest Generation was potentially liable and that had notbeen settled and dismissed at December 31, 2008. Midwest Generation had recorded a $52 million and$54 million liability at December 31, 2008 and 2007, respectively, related to this matter.

Midwest Generation recorded an undiscounted liability for its indemnity for future asbestos claims through2045. During the fourth quarter of 2007, the liability was reduced by $9 million based on updated estimatedlosses. In calculating future losses, various assumptions were made, including but not limited to, the settlementof future claims under the supplemental agreement with Commonwealth Edison as described above, thedistribution of exposure sites, and that no asbestos claims will be filed after 2044.

The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number ofassumptions. Future events, such as the number of new claims to be filed each year, the average cost ofdisposing of claims, as well as the numerous uncertainties surrounding asbestos litigation in the United States,could cause the actual costs to be higher or lower than projected.

Indemnity Provided as Part of the Acquisition of the Homer City Facilities

In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify thesellers with respect to specific environmental liabilities before and after the date of sale. Payments would betriggered under this indemnity by a valid claim from the sellers. EME guaranteed the obligations of EMEHomer City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximumpotential liability and does not have an expiration date. See “— Contingencies — EME Homer City NewSource Review Notice of Violation” for discussion of the NOV received by EME Homer City and associatedindemnity claims. EME has not recorded a liability related to this indemnity.

Indemnities Provided under Asset Sale Agreements

The asset sale agreements for the sale of EME’s international assets contain indemnities from EME to thepurchasers, including indemnification for taxes imposed with respect to operations of the assets prior to thesale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements havespecific expiration dates. Payments would be triggered under these indemnities by valid claims from thesellers or purchasers, as the case may be. At December 31, 2008 and 2007, EME had recorded a liability of$95 million (of which $51 million is classified as a current liability) and $101 million, respectively, related tothese matters.

In connection with the sale of various domestic assets, EME has from time to time provided indemnities to thepurchasers for taxes imposed with respect to operations of the asset prior to the sale. EME has also providedindemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigationmatters and/or environmental conditions). Due to the nature of the obligations under these indemnityagreements, a maximum potential liability cannot be determined. Not all indemnities under the asset saleagreements have specific expiration dates. Payments would be triggered under these indemnities by validclaims from the sellers or purchasers, as the case may be. At December 31, 2008, EME had recorded aliability of $13 million related to these matters.

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Indemnity Provided as Part of the Acquisition of Mountainview

In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect tospecific environmental claims related to SCE’s previously owned San Bernardino Generating Station, divestedby SCE in 1998 and reacquired as part of the Mountainview acquisition. SCE retained certain responsibilitieswith respect to environmental claims as part of the original divestiture of the station. The aggregate liabilityfor either party to the purchase agreement for damages and other amounts is a maximum of $60 million. Thisindemnification for environmental liabilities expires on or before March 12, 2033. SCE has not recorded aliability related to this indemnity.

Mountainview Filter Cake Indemnity

Mountainview owns and operates a power plant in Redlands, California. The plant utilizes water from on-sitegroundwater wells and City of Redlands (City) recycled water for cooling purposes. Unrelated to the operationof the plant, this water contains perchlorate. The pumping of the water removes perchlorate from the aquiferbeneath the plant and concentrates it in the plant’s wastewater treatment “filter cake.” Use of this impactedgroundwater for cooling purposes was mandated by Mountainview’s California Energy Commission permit.Mountainview has indemnified the City for cleanup or associated actions related to groundwater contaminatedby perchlorate due to the disposal of filter cake at the City’s solid waste landfill. The obligations under thisagreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded aliability related to this guarantee.

Other Edison International Indemnities

Edison International provides other indemnifications through contracts entered into in the normal course ofbusiness. These are primarily indemnifications against adverse litigation outcomes in connection withunderwriting agreements, and specified environmental indemnities and income taxes with respect to assetssold. Edison International’s obligations under these agreements may be limited in terms of time and/oramount, and in some instances Edison International may have recourse against third parties for certainindemnities. The obligated amounts of these indemnifications often are not explicitly stated, and the overallmaximum amount of the obligation under these indemnifications cannot be reasonably estimated. EdisonInternational has not recorded a liability related to these indemnities.

Contingencies

In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax andregulatory proceedings before various courts and governmental agencies regarding matters arising in theordinary course of business. Edison International believes the outcome of these other proceedings will notmaterially affect its results of operations or liquidity.

Environmental Remediation

Edison International is subject to numerous environmental laws and regulations, which require it to incursubstantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove theeffect of past operations on the environment.

Edison International believes that it is in substantial compliance with environmental regulatory requirements;however, possible future developments, such as the enactment of more stringent environmental laws andregulations, could affect the costs and the manner in which business is conducted and could cause substantialadditional capital expenditures. There is no assurance that additional costs would be recovered from customersor that Edison International’s financial position and results of operations would not be materially affected.

Edison International records its environmental remediation liabilities when site assessments and/or remedialactions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International

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reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for eachidentified site using currently available information, including existing technology, presently enacted laws andregulations, experience gained at similar sites, and the probable level of involvement and financial condition ofother potentially responsible parties. These estimates include costs for site investigations, remediation,operations and maintenance, monitoring and site closure. Unless there is a probable amount, EdisonInternational records the lower end of this reasonably likely range of costs (classified as other long-termliabilities) at undiscounted amounts.

As of December 31, 2008, Edison International’s recorded estimated minimum liability to remediate its 45identified sites at SCE (24 sites) and EME (21 sites primarily related to Midwest Generation) was $45 million,$41 million of which was related to SCE including $10 million related to San Onofre. This remediationliability is undiscounted. Edison International’s other subsidiaries have no identified remediation sites. Theultimate costs to clean up Edison International’s identified sites may vary from its recorded liability due tonumerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; thescarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developmentsresulting from investigatory studies; the possibility of identifying additional sites; and the time periods overwhich site remediation is expected to occur. Edison International believes that, due to these uncertainties, it isreasonably possible that cleanup costs could exceed its recorded liability by up to $173 million, all of which isrelated to SCE. The upper limit of this range of costs was estimated using assumptions least favorable toEdison International among a range of reasonably possible outcomes. In addition to its identified sites (sites inwhich the upper end of the range of costs is at least $1 million), SCE also has 30 immaterial sites whose totalliability ranges from $3 million (the recorded minimum liability) to $9 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $29 million ofits recorded liability, through an incentive mechanism (SCE may request to include additional sites). Underthis mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund theremaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties.SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costsincurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $40 million forits estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

Edison International’s identified sites include several sites for which there is a lack of currently availableinformation, including the nature and magnitude of contamination, and the extent, if any, that EdisonInternational may be held responsible for contributing to any costs incurred for remediating these sites. Thus,no reasonable estimate of cleanup costs can be made for these sites.

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of thenext several years are expected to range from $11 million to $31 million. Recorded costs were $29 million,$25 million and $14 million for 2008, 2007 and 2006, respectively.

Based on currently available information, Edison International believes it is unlikely that it will incur amountsin excess of the upper limit of the estimated range for its identified sites and, based upon the CPUC’sregulatory treatment of environmental remediation costs incurred at SCE, Edison International believes thatcosts ultimately recorded will not materially affect its results of operations or financial position. There can beno assurance, however, that future developments, including additional information about existing sites or theidentification of new sites, will not require material revisions to such estimates.


Edison International remains subject to examination and administrative appeals by the IRS for various taxyears. As part of a nationwide challenge of certain types of lease transactions, the IRS has raised issues aboutthe deferral of income taxes associated with its cross-border, leveraged leases. See Note 4, for further details.

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2009 FERC Rate Case

In an order issued in September 2008, the FERC accepted and made effective on March 1, 2009, subject torefund and settlement procedures, SCE’s proposed revisions to its tariff, filed in the 2009 transmission ratecase. The revisions reflected changes to SCE’s transmission revenue requirement and transmission rates, asdiscussed below.

SCE requested a $129 million increase in its retail transmission revenue requirements (or a 39% increase overthe current retail transmission revenue requirement) due to an increase in transmission capital-related costs andincreases in transmission operating and maintenance expenses that SCE expects to incur in 2009 to maintaingrid reliability. The transmission revenue requirement request is based on a return on equity of 12.7%, whichis composed of a 12.0% base ROE and 0.7% in transmission incentives previously approved by the FERC (see“FERC Transmission Incentives” below for further information). SCE is unable to predict the revenuerequirement that the FERC will ultimately authorize.

FERC Transmission Incentives

The Energy Policy Act of 2005 established incentive-based rate treatments for the transmission of electricenergy in interstate commerce by public utilities for the purpose of benefiting consumers by ensuringreliability and reducing the cost of delivered power by reducing transmission congestion. Pursuant to this act,in November 2007, the FERC issued an order granting incentives on three of SCE’s largest proposedtransmission projects. These include 125 basis point ROE adders on SCE’s proposed base ROE for SCE’sDPV2 and Tehachapi transmission projects and a 75 basis point ROE adder for SCE’s Rancho VistaSubstation Project (“Rancho Vista”).

In June 2007, the ACC denied the approval of the DPV2 project which resulted in an estimated two year delayof the project. SCE continues its efforts to obtain the regulatory approvals necessary to construct the DPV2project and continues to evaluate its options, which include but are not limited to, filing a new applicationwith the ACC and building the project in various phases.

The order also grants a 50 basis point ROE adder on SCE’s cost of capital for its entire transmission rate basein SCE’s next FERC transmission rate case for SCE’s participation in the CAISO. In addition, the order onincentives permits SCE to include in rate base 100% of prudently-incurred capital expenditures duringconstruction, also known as CWIP, of all three projects and 100% recovery of prudently-incurred abandonedplant costs for two of the projects, if either are cancelled due to factors beyond SCE’s control.

In August 2008, the CPUC filed an appeal of the FERC incentives order at the DC Circuit Court of Appeals.The court issued a ruling on November 6, 2008, accepting the CPUC’s request that the court refrain fromruling on the CPUC’s appeal until a final FERC order is issued in the 2008 CWIP case. (See “FERCConstruction Work in Progress Mechanism” below for further information).

FERC Construction Work in Progress Mechanism

FERC CWIP 2008

In February 2008, the FERC approved SCE’s revision to its tariff to collect 100% of CWIP in rate base for itsTehachapi, DPV2, and Rancho Vista, as authorized by FERC in its transmission incentives order discussedabove which resulted in an authorized base transmission revenue requirement of $45 million, subject to refund.In March 2008, the CPUC filed a petition for rehearing with the FERC on the FERC’s acceptance of SCE’sproposed ROE for CWIP and in another 2008 protest to an SCE compliance filing, requested an evidentiaryhearing to be set to further review SCE’s costs. SCE cannot predict the outcome of the matters in thisproceeding.

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FERC CWIP 2009

SCE filed its 2009 CWIP rate adjustment in October 2008 proposing a reduction to its CWIP revenuerequirement from $45 million to $39 million to be effective on January 1, 2009. Several parties, including theCPUC, filed protests to the October filing in November 2008, primarily contesting SCE’s proposed base ROEof 12.0%. The FERC issued an order in December 2008, allowing the proposed 2009 CWIP rates to go intoeffect on January 1, 2009, subject to refund, and directing that the 2009 CWIP ROE be made subject to theoutcome of the pending 2008 FERC CWIP proceeding. The FERC also consolidated all issues other than ROEwith SCE’s 2009 FERC rate case proceeding.

EME Homer City New Source Review Notice of Violation

On June 12, 2008, EME Homer City received an NOV from the US EPA alleging that, beginning in 1988,EME Homer City (or former owners of the Homer City facilities) performed repair or replacement projects atHomer City Units 1 and 2 without first obtaining construction permits as required by the Prevention ofSignificant Deterioration requirements of the CAA. The US EPA also alleges that EME Homer City has failedto file timely and complete Title V permits. EME Homer City has met with the US EPA and has expressed itsintent to explore the possibility of a settlement. If no settlement is reached and the DOJ files suit, litigationcould take many years to resolve the issues alleged in the NOV. EME Homer City cannot predict at this timewhat effect this matter may have on its facilities, its results of operations, financial position or cash flows.

EME Homer City has sought indemnification for liability and defense costs associated with the NOV from thesellers under the asset purchase agreement pursuant to which EME Homer City acquired the Homer Cityfacilities. The sellers responded by denying the indemnity obligation, but accepting the defense of the claims.

EME Homer City notified the sale-leaseback owner participants of the Homer City facilities of the NOV underthe operative indemnity provisions of the sale-leaseback documents. The owner participants of the Homer Cityfacilities, in turn, have sought indemnification and defense from EME Homer City for costs and liabilityassociated with the EME Homer City NOV. EME Homer City responded by undertaking the indemnityobligation and defense of the claims.

Four Corners CPUC Emissions Performance Standard Ruling

The emission performance standards adopted by the CPUC and CEC pursuant to SB 1368 prohibits SCE andother California load-serving entities from entering into long-term financial commitments with generators thatemit more than 1,100 pounds of CO2 per MWh, which would include most coal-fired plants. In January 2008,SCE filed a petition with the CPUC seeking clarification that the emission performance standard would notapply to capital expenditures required by existing agreements among the owners at Four Corners. The CPUCissued a proposed decision finding that the emission performance standard was not intended to apply to capitalexpenditures at Four Corners requested by SCE in its GRC for the period 2007 – 2011. In October 2008, theAssigned Commissioner and Administrative Law Judge issued a ruling withdrawing the proposed decision andseeking additional comment on whether the finding in the proposed decision should be changed and whetherSCE should be allowed to recover such capital expenditures. SCE estimates that its share of capitalexpenditures approved by the owners at Four Corners since the GHG emission performance standard decisionwas issued in January 2007 is approximately $43 million, of which approximately $8 million had beenexpended through December 31, 2008. The ruling also directs SCE to explain why certain information was notincluded in its petition and why the failure to include such information should not be considered misleading inviolation of CPUC rules. SCE filed its response and comments to the ruling in November and December 2008and cannot predict the outcome of this proceeding or estimate the amount, if any, of penalties or disallowancesthat may be imposed.

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ISO Disputed Charges

On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities ofAnaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization ofcertain transmission service related charges. The potential cost to SCE of the FERC order, net of amountsSCE expects to receive through the PX, SCE’s scheduling coordinator at the pertinent time, is estimated to beapproximately $20 million to $25 million, including interest. The order has been the subject of continuinglegal proceedings since it was issued. SCE believes that the most recent substantive order FERC has issued inthe proceedings correctly allocates responsibility for these ISO charges. However, SCE cannot predict the finaloutcome of the rehearing. If a subsequent regulatory decision changes the allocation of responsibility for thesecharges, and SCE is required to pay these charges as a transmission owner, SCE may seek recovery in itsreliability service rates. SCE cannot predict whether recovery of these charges in its reliability service rateswould be permitted.

Leveraged Lease Investments

At December 31, 2008, Edison Capital had a net leveraged lease investment, before deferred taxes, of$50 million in three aircraft leased to American Airlines. American Airlines reported net losses during 2008and previously reported losses for a number of years prior to 2006. A default in the leveraged lease byAmerican Airlines could result in a loss of some or all of Edison Capital’s lease investment. At December 31,2008, American Airlines was current in its lease payments to Edison Capital.

Midwest Generation New Source Review Notice of Violation

On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in theearly 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacementprojects at six Illinois coal-fired electric generating stations in violation of the Prevention of SignificantDeterioration requirements and of the New Source Performance Standards of the CAA, including allegedrequirements to obtain a construction permit and to install best available control technology at the time of theprojects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certainoperating permit requirements under Title V of the CAA. Finally, the US EPA alleges violations of certainopacity and particulate matter standards at the Illinois Plants. The NOV does not specify the penalties or otherrelief that the US EPA seeks for the alleged violations. Midwest Generation, Commonwealth Edison, the USEPA, and the DOJ are in talks designed to explore the possibility of a settlement. If the settlement talks failand the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. MidwestGeneration cannot predict the outcome of this matter or estimate the impact on its facilities, its results ofoperations, financial position or cash flows.

On August 13, 2007, Midwest Generation and Commonwealth Edison received a letter signed by severalChicago-based environmental action groups stating that, in light of the NOV, the groups are examining thepossibility of filing a citizen suit against Midwest Generation and Commonwealth Edison based presumablyon the same or similar theories advanced by the US EPA in the NOV.

By letter dated August 8, 2007, Commonwealth Edison advised EME that Commonwealth Edison believes itis entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a resultof the NOV. By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification toEME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if theenvironmental groups were to file suit. Midwest Generation and Commonwealth Edison are cooperating withone another in responding to the NOV.

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Navajo Nation Litigation

The Navajo Nation filed a complaint in June 1999 in the District Court against SCE, among other defendants,arising out of the coal supply agreement for Mohave. The complaint asserts claims for, among other things,violations of the federal RICO statute, interference with fiduciary duties and contractual relations, fraudulentmisrepresentations by nondisclosure, and various contract-related claims. The complaint claims that thedefendants’ actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coalsupplied to Mohave. The complaint seeks damages of not less than $600 million, trebling of that amount, andpunitive damages of not less than $1 billion. In March 2001, the Hopi Tribe was permitted to intervene as anadditional plaintiff but has not yet identified a specific amount of damages claimed. The case was stayed atthe request of the parties in October 2004, but was reinstated to the active calendar in March 2008.

A related case against the U.S. Government is presently before the U.S. Supreme Court. The outcome of thatcase could affect the Navajo Nation’s pursuit of claims against SCE. A decision from the U.S. Supreme Courtis expected in mid-2009.

SCE cannot predict the outcome of the Tribe’s complaints against SCE or the ultimate impact on thesecomplaints of the on-going litigation by the Navajo Nation against the U.S. Government in the related case.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to the amount of available financialprotection, which is currently approximately $12.5 billion. SCE and other owners of San Onofre and PaloVerde have purchased the maximum private primary insurance available ($300 million). The balance iscovered by the industry’s retrospective rating plan that uses deferred premium charges to every reactorlicensee if a nuclear incident at any licensed reactor in the United States results in claims and/or costs whichexceed the primary insurance at that plant site.

Federal regulations require this secondary level of financial protection. The NRC exempted San Onofre Unit 1from this secondary level, effective June 1994. Beginning October 29, 2008, the maximum deferred premiumfor each nuclear incident is approximately $118 million per reactor, but not more than approximately$18 million per reactor may be charged in any one year for each incident. The maximum deferred premiumper reactor and the yearly assessment per reactor for each nuclear incident is adjusted for inflation at leastonce every five years. The most recent inflation adjustment took effect on October 29, 2008. Based on itsownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclearincident. However, it would have to pay no more than approximately $35 million per incident in any one year.Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and aresubject to adjustment for inflation. If the public liability limit above is insufficient, federal law contemplatesthat additional funds may be appropriated by Congress. This could include an additional assessment on alllicensed reactor operators as a measure for raising further electric utility revenue.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofreand Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 millionalso has been purchased in amounts greater than federal requirements. Additional insurance covers part ofreplacement power expenses during an accident-related nuclear unit outage. A mutual insurance companyowned by utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by thearrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessedretrospective premium adjustments of up to approximately $45 million per year. Insurance premiums arecharged to operating expense.

Palo Verde Nuclear Generating Station Outage and Inspection

The NRC held three special inspections of Palo Verde, between March 2005 and February 2007. Thecombination of the results of the first and third special inspections caused the NRC to undertake an additional

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oversight inspection of Palo Verde. This additional inspection, known as a supplemental inspection, wascompleted in December 2007. In addition, Palo Verde was required to take additional corrective actions basedon the outcome of completed surveys of its plant personnel and self-assessments of its programs andprocedures. The NRC and APS defined and agreed to inspection and survey corrective actions that the NRCembodied in a Confirmatory Action Letter, which was issued in February 2008. APS is presently on track tocomplete the corrective actions required to close the Confirmatory Action Letter by mid-2009. Palo Verdeoperation and maintenance costs (including overhead) increased in 2007 by approximately $7 million from2006. SCE estimates that operation and maintenance costs will increase by approximately $23 million (in2007 dollars) over the two year period 2008 – 2009, from 2007 recorded costs including overhead costs. SCEis unable to estimate how long SCE will continue to incur these costs. In the 2009 GRC, SCE requestedrecovery of, and two-way balancing account treatment for, Palo Verde operation and maintenance expensesincluding costs associated with these corrective actions. If approved, this would provide for recovery of thesecosts over the three-year GRC cycle.

Procurement of Renewable Resources

California law requires SCE to increase its procurement of renewable resources by at least 1% of its annualretail electricity sales per year so that 20% of its annual electricity sales are procured from renewableresources by no later than December 31, 2010.

It is unlikely that SCE will have 20% of its annual electricity sales procured from renewable resources by2010. However, SCE may still meet the 20% target by utilizing the flexible compliance rules, such as bankingof past surplus and earmarking of future deliveries from executed contracts. SCE continues to engage inseveral renewable procurement activities including formal solicitations approved by the CPUC, bilateralnegotiations with individual projects and other initiatives.

Under current CPUC decisions, potential penalties for SCE’s inability to achieve its renewable procurementobjectives for any year will be considered by the CPUC in the context of the CPUC’s review of SCE’s annualcompliance filing. Under the CPUC’s current rules, the maximum penalty for inability to achieve renewableprocurement targets is $25 million per year. SCE does not believe it will be assessed penalties for 2008 or theprior years and cannot predict whether it will be assessed penalties for future years.

RPM Buyers’ Complaint

On May 30, 2008, a group of entities referring to themselves as the “RPM Buyers” filed a complaint at theFERC asking that PJM’s RPM, as implemented through the transitional base residual auctions establishingcapacity payments for the period from June 1, 2008 through May 31, 2011, be found to have produced unjustand unreasonable capacity prices. On September 19, 2008, the FERC dismissed the RPM Buyers’ complaint,finding that the RPM Buyers had failed to allege or prove that any party violated PJM’s tariff and marketrules, and that the prices determined during the transition period were determined in accordance with PJM’sFERC-approved tariff. On October 20, 2008, the RPM Buyers requested rehearing of the FERC’s orderdismissing their complaint. This matter is currently pending before the FERC. EME cannot predict theoutcome of this matter.

Spent Nuclear Fuel

Under federal law, the DOE is responsible for the selection and construction of a facility for the permanentdisposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its contractualobligation to begin acceptance of spent nuclear fuel by January 31, 1998. It is not certain when the DOE willbegin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended delays by theDOE have led to the construction of costly alternatives and associated siting and environmental issues. SCEhas paid the DOE the required one-time fee applicable to nuclear generation at San Onofre (approximately$24 million, plus interest). SCE has also been paying a required quarterly fee equal to 0.1¢ per-kWh of

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nuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating agent, filed acomplaint against the DOE in the United States Court of Federal Claims seeking damages for the DOE’sfailure to meet its obligation to begin accepting spent nuclear fuel from San Onofre.

SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Suchinterim storage for San Onofre is on-site.

APS, as operating agent, has primary responsibility for the interim storage of spent nuclear fuel at Palo Verde.Palo Verde plans to add storage capacity incrementally to maintain full core off-load capability for all threeunits. In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde hasconstructed an independent spent fuel storage facility.

Note 7. Accumulated Other Comprehensive Income (Loss)

Edison International’s accumulated other comprehensive income (loss), including discontinued operations,consists of:

UnrealizedGains

(Losses) onCash Flow

Hedges

ForeignCurrency

TranslationAdjustment

Pensionand

PBOP–Net Loss

Pensionand

PBOP–Prior

ServiceCost

AccumulatedOther

ComprehensiveIncome (Loss)

Balance at December 31, 2006 $ 110 $ 1 $ (37) $ 4 $ 78Change for 2007 (170) (2) 3 (1) (170)

Balance at December 31, 2007 (60) (1) (34) 3 (92)Change for 2008 300 (3) (36) (2) 259

Balance at December 31, 2008 $ 240 $ (4) $ (70) $ 1 $ 167

SFAS No. 158 — postretirement benefits is discussed in “Pension Plans and Postretirement Benefits OtherThan Pensions” in Note 5.

Unrealized gains on cash flow hedges, net of tax, at December 31, 2008, included unrealized gains oncommodity hedges related to Midwest Generation and EME Homer City futures and forward electricitycontracts that qualify for hedge accounting. These gains arise because current forecasts of future electricityprices in these markets are lower than the contract prices. As EME’s hedged positions for continuingoperations are realized, $149 million, after tax, of the net unrealized gains on cash flow hedges atDecember 31, 2008 are expected to be reclassified into earnings during the next 12 months. Managementexpects that reclassification of net unrealized gains will increase nonutility power generation revenuerecognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 monthscould vary materially from this estimated amount as a result of changes in market conditions. The maximumperiod over which a cash flow hedge is designated is through December 31, 2011.

Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of thetransaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognizedin earnings. EME recorded net gains (losses) of $7 million, $(41) million and $(6) million in 2008, 2007 and2006, respectively, representing the amount of cash flow hedges’ ineffectiveness for continuing operations,reflected in nonutility power generation operating revenues on Edison International’s consolidated incomestatements.

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of theU.S. Bankruptcy Code. EME had power contracts with Lehman Brothers Commodity Services, Inc., asubsidiary of Lehman Brothers Holdings, for Midwest Generation for 2009 and 2010. Lehman BrothersCommodity Services also filed for bankruptcy protection on October 3, 2008. The obligations of Lehman

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Brothers Commodity Services under the power contracts were guaranteed by Lehman Brothers Holdings.These contracts qualified as cash flow hedges under SFAS No. 133 until EME dedesignated the powercontracts effective September 12, 2008 when it determined that it was no longer probable that performancewould occur. The amount recorded in accumulated comprehensive income (loss) related to the effectiveportion of the hedges was $24 million pre-tax ($15 million, after tax) on that date. Since the power contractsare no longer being accounted for as cash flow hedges under SFAS No. 133 and subsequently wereterminated, the subsequent change in fair value was recorded as an unrealized loss in 2008 and included innonutility generation power revenues on EME’s consolidated statement of income. Under SFAS No. 133, thepre-tax amount recorded in accumulated other comprehensive income (loss) will be reclassified to operatingnonutility generation power revenue based on the original forecasted transactions in 2009 ($15 million) and2010 ($9 million), unless it becomes probable that the forecasted transactions will no longer occur.

EME has established claims in the amount of $48 million related to the contracts terminated with LehmanBrothers Holdings and its subsidiary as described above through the termination provisions of its masternetting agreements with a Lehman Brothers Holdings subsidiary. Such claims have been fully reserved and areincluded net in prepaid expenses and other on EME’s consolidated balance sheet.

Note 8. Property and Plant

Nonutility Property

Nonutility property included on the consolidated balance sheets is composed of:


Furniture and equipment $ 82 $ 90Building, plant and equipment 5,250 4,490Land (including easements) 80 85Emission allowances 1,305 1,305Leasehold improvements 132 110Construction in progress 544 591

7,393 6,671Accumulated provision for depreciation (2,019) (1,765)

Nonutility property – net $ 5,374 $ 4,906

The power sales agreements of certain wind projects qualify as operating leases under EITF No. 01-8, andSFAS No. 13, “Accounting for Leases.” The carrying amount and related accumulated depreciation of theproperty of these wind projects totaled $901 million and $62 million, respectively, at December 31, 2008, and$559 million and $28 million, respectively, at December 31, 2007. EME records rental income from windprojects that are accounted for as operating leases as electricity is delivered at rates defined in power salesagreements. Revenue from these power sales agreements were $46 million, $24 million and $10 million in2008, 2007 and 2006, respectively.

Asset Retirement Obligations

As a result of the adoption of SFAS No. 143 in 2003, Edison International recorded the fair value of itsliability for legal AROs, which was primarily related to the decommissioning of SCE’s nuclear powerfacilities. In addition, SCE capitalized the initial costs of the ARO into a nuclear-related ARO regulatory asset,and also recorded an ARO regulatory liability as a result of timing differences between the recognition ofcosts recorded in accordance with the standard and the recovery of the related asset retirement costs throughthe rate-making process. SCE has collected in rates amounts for the future costs of removal of its nuclearassets, and has placed those amounts in independent trusts. The fair value of the nuclear decommissioning

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trusts was $2.5 billion at December 31, 2008. For a further discussion about nuclear decommissioning trustssee “Nuclear Decommissioning Commitment” in Note 6 and “Nuclear Decommission Trusts” in Note 10.

A reconciliation of the changes in the ARO liability is as follows:

In millions 2008 2007 2006

Beginning balance $ 2,892 $ 2,759 $ 2,628Accretion expense 176 169 160Revisions (13) 3 —Liabilities added 22 7 42Liabilities settled (35) (46) (71)

Ending balance $ 3,042 $ 2,892 $ 2,759

The ARO liability as of December 31, 2008 includes an ARO liability of $2.9 billion related to nucleardecommissioning.

Note 9. Supplemental Cash Flow Information

Edison International’s supplemental cash flows information is:


Cash payments for interest and taxes:Interest – net of amounts capitalized $ 638 $ 709 $ 739Tax payments – net $ 377 $ 332 $ 826Noncash investing and financing activities:Details of debt exchange:

Pollution-control bonds redeemed $ — $ — $ (331)Pollution-control bonds issued $ — $ — $ 331

Details of capital lease obligations:Capital lease purchased $ — $ (10) $ —Capital lease obligation issued $ — $ 10 $ —

Dividends declared but not paidCommon Stock $ 101 $ 99 $ 94Preferred and preference stock of utility not subject to mandatory redemption $ 13 $ 13 $ 9

Details of assets acquired:Fair value of assets acquired $ — $ 41 $ 29Liabilities assumed $ — $ — $ —

Net assets acquired $ — $ 41 $ 29

Details of consolidation of variable interest entities:Assets $ 3 $ 12 $ 18Liabilities $ (4) $ (5) $ (4)

In connection with certain wind projects acquired during the past three years, the purchase price includedpayments that were due upon the start and/or completion of construction. Accordingly, EME accrued forestimated payments or made payments that were due upon commencement of construction and/or completionof construction scheduled during 2007 through 2009.

During the year ended December 31, 2006, EME received a capital contribution of $76 million in the form ofownership interests in a portfolio of wind projects and a small biomass project. Refer to Notes 16 and 18 forfurther discussions.

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Note 10. Fair Value Measurements

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer aliability in an orderly transaction between market participants at the measurement date (referred to as an “exitprice” in SFAS No. 157). SFAS No. 157 clarifies that a fair value measurement for a liability should reflectthe entity’s non-performance risk. In addition, SFAS No. 157 establishes a fair value hierarchy that prioritizesthe inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority tounadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements)and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair valuehierarchy under SFAS No. 157 are:

• Level 1 – Unadjusted quoted prices in active markets that are accessible at the measurement date foridentical assets and liabilities;

• Level 2 – Pricing inputs include quoted prices for similar assets and liabilities in active markets and inputsthat are observable for the asset or liability, either directly or indirectly, for substantially the full term ofthe financial instrument; and

• Level 3 – Prices or valuations that require inputs that are both significant to the fair value measurementsand unobservable.

Edison International’s assets and liabilities carried at fair value primarily consist of derivative contracts, SCEnuclear decommissioning trust investments and money market funds. Derivative contracts primarily relate topower and gas and include contracts for forward physical sales and purchases, options and forward priceswaps which settle only on a financial basis (including futures contracts). Derivative contracts can be exchangetraded or over-the-counter traded.

The fair value of derivative contracts takes into account quoted market prices, time value of money, volatilityof the underlying commodities and other factors. Derivatives that are exchange traded in active markets foridentical assets or liabilities are classified as Level 1. The majority of EME’s derivative contracts used forhedging purposes are based on forward market prices in active markets (PJM West Hub, Northern Illinois Huband AEP/Dayton) adjusted for non-performance risks. EME obtains forward market prices from tradedexchanges (ICE Futures U.S. or New York Mercantile Exchange) and available broker quotes. Then, EMEselects a primary source that best represents traded activity for each market to develop observable forwardmarket prices in determining the fair value of these positions. Broker quotes or prices from exchanges areused to validate and corroborate the primary source. These price quotations reflect mid-market prices (averageof bid and ask) and are obtained from sources that EME believes to provide the most liquid market for thecommodity. EME considers broker quotes to be observable when corroborated with other information whichmay include a combination of prices from exchanges, other brokers and comparison to executed trades. Themajority of the fair value of EME’s derivative contracts determined in this manner are classified as Level 2.SCE’s Level 2 derivatives primarily consist of financial natural gas swaps, fixed float swaps, and natural gasphysical trades for which SCE obtains the applicable Henry Hub and basis forward market prices from theNew York Mercantile Exchange and Intercontinental Exchange.

Level 3 includes the majority of SCE’s derivatives, including over-the-counter options, bilateral contracts,capacity contracts, and QF contracts. The fair value of these SCE derivatives is determined usinguncorroborated non-binding broker quotes (from one or more brokers) and models which may require SCE toextrapolate short-term observable inputs in order to calculate fair value. Broker quotes are obtained fromseveral brokers and compared against each other for reasonableness. SCE has Level 3 fixed float swaps forwhich SCE obtains the applicable Henry Hub and basis forward market prices from the New York MercantileExchange. However, these swaps have contract terms that extend beyond observable market data and theunobservable inputs incorporated in the fair value determination are considered significant compared to theoverall swap’s fair value.

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Level 3 also includes derivatives that trade infrequently (such as financial transmission rights, FTRs and CRRsin the California market and over-the-counter derivatives at illiquid locations), derivatives with counterpartiesthat have significant non-performance risks as discussed below and long-term power agreements. For illiquidfinancial transmission rights, FTRs and CRRs, Edison International reviews objective criteria related to systemcongestion and other underlying drivers and adjusts fair value when Edison International concludes a changein objective criteria would result in a new valuation that better reflects the fair value. Recent auction prices areused to determine the fair value of short-term CRRs. Edison International recorded liquidity reserves againstthe long-term CRRs fair values since there were no quoted long-term market prices for the CRRs andinsufficient evidence of long-term market prices.

Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term poweragreements, fair value is based upon a discounting of future electricity and natural gas prices derived from aproprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk andmarket liquidity. Changes in fair value are based on changes to forward market prices, including forecastedprices for illiquid forward periods. In circumstances where Edison International cannot verify fair value withobservable market transactions, it is possible that a different valuation model could produce a materiallydifferent estimate of fair value. As markets continue to develop and more pricing information becomesavailable, Edison International continues to assess valuation methodologies used to determine fair value.

In assessing non-performance risks, EME reviews credit ratings of counterparties (and related default ratesbased on such credit ratings) and prices of credit default swaps. The market price (or premium) for creditdefault swaps represents the price that a counterparty would pay to transfer the risk of default, typicallybankruptcy, to another party. A credit default swap is not directly comparable to the credit risks of derivativecontracts, but provides market information of the related risk of non-performance. In light of recent marketevents, EME utilized market prices for credit default swaps in reducing the fair value of derivative assets by$6 million at December 31, 2008.

Investments in money market funds are generally classified as Level 1 as fair value is determined byobservable market prices (unadjusted) in active markets. In 2008, EME had invested $20 million in theReserve Primary Fund (a money market fund). The Reserve incurred a loss related to debt securities ofLehman Brothers Holdings and has announced liquidation of the Reserve. EME reduced the fair value of theinvestment by $1 million and transferred the remaining balance into Level 3 during the third quarter of 2008as observable market prices were not available. During the fourth quarter of 2008, EME received $16 millionin settlements resulting in the ending balance of $3 million at December 31, 2008 classified in Level 3.

The SCE nuclear decommissioning trust investments include equity securities, U.S. treasury securities andother fixed-income securities. Equity and treasury securities are classified as Level 1 as fair value isdetermined by observable market prices in active or highly liquid and transparent markets. The remainingfixed-income securities are classified as Level 2. The fair value of these financial instruments is based onevaluated prices that reflect significant observable market information such as reported trades, actual tradeinformation of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers andrelevant credit information.

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The following table sets forth financial assets and liabilities that were accounted for at fair value as ofDecember 31, 2008 by level within the fair value hierarchy:

In millions Level 1 Level 2 Level 3Netting andCollateral(1)

Total atDecember 31,

2008(Unaudited)

Assets at Fair ValueMoney market funds(2) $ 3,543 $ — $ 3 $ — $ 3,546Derivative contracts 4 419 448 (225) 646Nuclear decommissioning trusts(3) 1,502 1,026 — — 2,528Long-term disability plan 7 — — — 7

Total assets(4) 5,056 1,445 451 (225) 6,727Liabilities at Fair Value

Derivative contracts (2) (397) (753) 123 (1,029)

Net assets (liabilities) $ 5,054 $ 1,048 $ (302) $ (102) $ 5,698

(1) Represents cash collateral and the impact of netting across the levels of the fair value hierarchy. Nettingamong positions classified within the same level is included in that level.

(2) Included in cash and cash equivalents and short-term investments on Edison International’s consolidatedbalance sheet.

(3) Excludes net liabilities of $4 million for interest and dividend receivables and receivables related topending securities sales and payables related to pending securities purchases.

(4) Excludes $32 million of cash surrender value of life insurance investments for deferred compensation.

The following table sets forth a summary of changes in the fair value of Level 3 derivative contracts, net forthe year ended December 31, 2008:

In millions

Year EndedDecember 31,

2008

Fair value of derivative contracts, net at January 1, 2008 $ 98Total realized/unrealized gains (losses):

Included in earnings(1) 297Included in regulatory assets and liabilities(2) (644)Included in accumulated other comprehensive income (2)

Purchases and settlements, net (36)Transfers in or out of Level 3 (18)

Fair value of derivative contracts, net at December 31 $ (305)

Change during the period in unrealized gains (losses) related tonet derivative contracts, held at December 31, 2008(3) $ (448)

(1) $297 million reported in “Nonutility power generation” revenue on Edison International’sconsolidated statement of income for the year ended December 31, 2008.

(2) Due to regulatory mechanisms, SCE’s realized and unrealized gains and losses are recorded asregulatory assets and liabilities.

(3) $125 million reported in “Nonutility power generation” revenue on Edison International’sconsolidated statements of income for the year ended December 31, 2008. The remainder ofthe unrealized gains (losses) relates to SCE. See (2) above.

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Nuclear Decommissioning Trusts

SCE is collecting in rates amounts for the future costs of removal of its nuclear assets, and has placed thoseamounts in independent trusts. Funds collected, together with accumulated earnings, will be utilized solely fordecommissioning. The CPUC has set certain restrictions related to the investments of these trusts.

Trust investments (at fair value) include:

In millions Maturity DatesDecember 31,

2008December 31,

2007

Municipal bonds 2009 – 2044 $ 629 $ 561Stocks – 1,308 1,968United States government issues 2009 – 2049 304 552Corporate bonds 2009 – 2047 260 241Short-term investments, primarily cash equivalents 2009 23 56

Total $ 2,524 $ 3,378

Note: Maturity dates as of December 31, 2008.

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatoryliability. Net earnings (losses) were $(10) million, $143 million and $130 million in 2008, 2007 and 2006,respectively. Proceeds from sales of securities (which are reinvested) were $3.1 billion, $3.7 billion and$3.0 billion in 2008, 2007 and 2006, respectively. Unrealized holding gains, net of losses, were $618 millionand $1.1 billion at December 31, 2008 and 2007, respectively. Approximately 92% of the cumulative trustfund contributions were tax-deductible.

The following table sets forth a summary of changes in the fair value of the trust for year ended December 31,2008:

In millions

Balance at beginning of period $ 3,378Realized losses – net (65)Unrealized losses – net (545)Other-than-temporary impairment (317)Earnings and other 73

Balance at December 31, 2008 $ 2,524

The decrease in the trust investments was primarily due to net unrealized losses and other-than-temporaryimpairment resulting from a volatile stock market environment. Due to regulatory mechanisms, earnings andrealized gains and losses (including other-than-temporary impairments) have no impact on electric utilityrevenue.

Nuclear decommissioning costs are recovered in utility rates. These costs are expected to be funded fromindependent decommissioning trusts, which currently receive contributions of approximately $46 million peryear. Contributions to the decommissioning trusts are reviewed every three years by the CPUC. The next filingis in April 2009 for contribution changes in 2011. These contributions are determined based on an analysis ofthe current value of trusts assets and long-term forecasts of cost escalation, the estimate and timing ofdecommissioning costs, and after-tax return on trust investments. Favorable or unfavorable investmentperformance in a period will not change the amount of contributions for that period. However, trustperformance for the three years leading up to a CPUC review proceeding will provide input into futurecontributions. The CPUC has set certain restrictions related to the investments of these trusts. If additionalfunds are needed for decommissioning, it is probable that the additional funds will be recoverable throughcustomer rates.

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Fair Values of Financial Instruments

The carrying amounts and fair values of financial instruments are:

In millionsCarryingAmount

FairValue

CarryingAmount

FairValue

2008 2007December 31,

Derivatives:Interest rate hedges $ — $ — $ (33) $ (33)Foreign currency hedge (33) (33) 3 3Commodity price assets 585 585 82 82Commodity price liabilities (944) (944) (214) (214)QF power contracts liabilities (2) (2) (3) (3)

Other:Decommissioning trusts 2,524 2,524 3,378 3,378Long-term debt (10,950) (10,637) (9,016) (8,995)Long-term debt due within one year (174) (175) (18) (18)

Trading Activities:Assets 286 286 141 141Liabilities (173) (173) (9) (9)

Fair values are based on: brokers’ quotes and bank evaluations for interest rate hedges, foreign currencyhedges and long-term debt. See “Fair Value Measurements” above for discussion of valuation of derivativesand the decommissioning trusts.

In January and February 2008, SCE settled interest rate locks resulting in realized losses of $33 million. Arelated regulatory asset was recorded in this amount and SCE is amortizing and recovering this amount asinterest expense associated with its 2008 financings.

Note 11. Regulatory Assets and Liabilities

Included in SCE’s regulatory assets and liabilities are regulatory balancing accounts. Sales balancing accountsaccumulate differences between recorded electric utility revenue and revenue SCE is authorized to collectthrough rates. Cost balancing accounts accumulate differences between recorded costs and costs SCE isauthorized to recover through rates. Undercollections are recorded as regulatory balancing account assets.Overcollections are recorded as regulatory balancing account liabilities. SCE’s regulatory balancing accountsaccumulate balances until they are refunded to or received from SCE’s customers through authorized rateadjustments. Primarily all of SCE’s balancing accounts can be classified as one of the following types:generation-revenue related, distribution-revenue related, generation-cost related, distribution-cost related,transmission-cost related or public purpose and other cost related.

Balancing account undercollections and overcollections accrue interest based on a three-month commercialpaper rate published by the Federal Reserve. Income tax effects on all balancing account changes are deferred.

Amounts included in regulatory assets and liabilities are generally recorded with corresponding offsets to theapplicable income statement accounts.

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Regulatory Assets

Regulatory assets included on the consolidated balance sheets are:


Current:Regulatory balancing accounts $ 455 $ 99Energy derivatives 138 71Purchased-power settlements — 8Deferred FTR proceeds 9 15Other 3 4

$ 605 $ 197

Long-term:Regulatory balancing accounts $ 29 $ 15Flow-through taxes – net 1,337 1,110ARO 224 —Unamortized nuclear investment – net 375 405Nuclear-related ARO investment – net 278 297Unamortized coal plant investment – net 79 94Unamortized loss on reacquired debt 309 331SFAS No. 158 pensions and other postretirement benefits 1,882 231Energy derivatives 723 70Environmental remediation 40 64Other 138 104

$ 5,414 $ 2,721

Total Regulatory Assets $ 6,019 $ 2,918

SCE’s regulatory assets related to energy derivatives are an offset to unrealized losses on recorded derivativesand an offset to lease accruals. SCE’s regulatory assets related to purchased-power settlements were recoveredthrough October 2008. SCE’s regulatory assets related to deferred FTR proceeds represent the deferral ofelectric utility revenue associated with FTRs that SCE received as a transmission owner from the annual ISOFTR auction. The deferred FTR proceeds were recognized through March 2009. Based on current regulatoryratemaking and income tax laws, SCE expects to recover its net regulatory assets related to flow-through taxesover the life of the assets that give rise to the accumulated deferred income taxes. SCE’s regulatory assetrelated to the ARO represents timing differences between the recognition of AROs in accordance withgenerally accepted accounting principles and the amounts recognized for rate-making purposes. SCE’s nuclear-related regulatory assets related to San Onofre are expected to be recovered by 2022. SCE’s nuclear-relatedregulatory assets related to Palo Verde are expected to be recovered by 2027. SCE’s net regulatory assetrelated to its unamortized coal plant investment is being recovered through June 2016. SCE’s net regulatoryasset related to its unamortized loss on reacquired debt will be recovered over the remaining originalamortization period of the reacquired debt over periods ranging from one year to 30 years. SCE’s regulatoryasset related to SFAS No. 158 represents the offset to the additional amounts recorded in accordance withSFAS No. 158 (see “Pension Plans and Postretirement Benefits Other Than Pensions” discussion in Note 5).This amount will be recovered through rates charged to customers. SCE’s regulatory asset related toenvironmental remediation represents the portion of SCE’s environmental liability recognized at the end of theperiod in excess of the amount that has been recovered through rates charged to customers. This amount willbe recovered in future rates as expenditures are made.

SCE’s unamortized nuclear investment – net and unamortized coal plant investment – net regulatory assetsearned a 8.75% and 8.77% return in 2008 and 2007, respectively.

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Regulatory Liabilities

Regulatory liabilities included on the consolidated balance sheets are:


Current:Regulatory balancing accounts $ 1,068 $ 967Rate reduction notes – transition cost overcollection 20 20Energy derivatives 6 10Deferred FTR costs 13 19Other 4 3

$ 1,111 $ 1,019

Long-term:Regulatory balancing accounts $ 43 $ —ARO — 793Costs of removal 2,368 2,230SFAS No. 158 pensions and other postretirement benefits — 308Energy derivatives — 27Employee benefit plans 70 75

$ 2,481 $ 3,433

Total Regulatory Liabilities $ 3,592 $ 4,452

Rate reduction notes – transition cost overcollection represents the nonbypassable rates charged to customerssubsequent to the final principal payment of SCE’s rate reduction bonds. These amounts will be refunded toratepayers. SCE’s regulatory liabilities related to energy derivatives are an offset to unrealized gains onrecorded derivatives and an offset to a lease prepayment. SCE’s regulatory liabilities related to deferred FTRcosts represent the deferral of the costs associated with FTRs that SCE purchased during the annual ISOauction process. The FTRs provide SCE with scheduling priority in certain transmission grid congestion areasin the day-ahead market. The FTRs meet the definition of a derivative instrument and are recorded at fairvalue and marked to market each reporting period. Any fair value change for FTRs is reflected in the deferredFTR costs regulatory liability. The deferred FTR costs are recognized as FTRs are used or expire in variousperiods through March 2009. SCE’s regulatory liability related to the ARO represents timing differencesbetween the recognition of AROs in accordance with generally accepted accounting principles and theamounts recognized for rate-making purposes. SCE’s regulatory liabilities related to costs of removal representelectric utility revenue collected for asset removal costs that SCE expects to incur in the future. SCE’sregulatory liability related to SFAS No. 158 represents the offset to the additional amounts recorded inaccordance with SFAS No. 158 (see “Pension Plans and Postretirement Benefits Other Than Pensions”discussion in Note 5). This amount will be returned to ratepayers in some future rate-making proceeding.SCE’s regulatory liabilities related to employee benefit plan expenses represent pension costs recoveredthrough rates charged to customers in excess of the amounts recognized as expense or the difference betweenthese costs calculated in accordance with rate-making methods and these costs calculated in accordance withSFAS No. 87, and PBOP costs recovered through rates charged to customers in excess of the amountsrecognized as expense. These balances will be returned to ratepayers in some future rate-making proceeding,be charged against expense to the extent that future expenses exceed amounts recoverable through the rate-making process, or be applied as otherwise directed by the CPUC.

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Note 12. Other Nonoperating Income and Deductions

Other nonoperating income and deductions are as follows:


AFUDC $ 54 $ 46 $ 32Increase in cash surrender value of life insurance policies 24 23 21Performance-based incentive awards 3 4 19Other 20 16 13

Total utility nonoperating income $ 101 $ 89 $ 85Nonutility nonoperating income 12 6 48

Total other nonoperating income $ 113 $ 95 $ 133

Various penalties $ 59 $ 5 $ 23Civic, political and related activities and donations 42 35 29Other 22 5 8

Total utility nonoperating deductions $ 123 $ 45 $ 60Nonutility nonoperating deductions 2 — 3

Total other nonoperating deductions $ 125 $ 45 $ 63

In 2006, nonutility nonoperating income primarily reflects Edison Capital’s $19 million pre-tax gain on thesale of certain investments, including Edison Capital’s interest in an affordable housing project, the recognitionat EME of an estimated business interruption insurance claim of $11 million and EME’s $8 million gainrelated to the receipt of shares from Mirant Corporation from settlement of a claim recorded during the firstquarter of 2006.

The 2008 increase in utility nonoperating deductions primarily resulted form a CPUC decision in September2008 related to SCE incentives claimed under a CPUC-approved PBR mechanism. The decision required SCEto refund $28 million and $20 million related to customer satisfaction and employee safety reportingincentives, respectively, and further required SCE to forego claimed incentives of $20 million and $15 millionrelated to customer satisfaction and employee safety reporting, respectively. The decision also required SCE torefund $33 million for employee bonuses related to the program and imposed a statutory penalty of$30 million. During the third quarter of 2008, SCE recorded a charge of $49 million, after-tax ($60 million,pre-tax) related to this decision.

Note 13. Jointly Owned Utility Projects

SCE owns interests in several generating stations and transmission systems for which each participant providesits own financing. SCE’s proportionate share of expenses for each project is included on the consolidatedstatements of income.

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The following is SCE’s investment in each project as of December 31, 2008:

In millionsInvestmentin Facility

AccumulatedDepreciation

andAmortization

OwnershipInterest

Transmission systems:Eldorado $ 71 $ 13 60%Pacific Intertie 310 103 50

Generating stations:Four Corners Units 4 and 5(coal) 554 454 48Mohave (coal) 345 294 56Palo Verde (nuclear) 1,824 1,501 16San Onofre (nuclear) 4,833 4,024 78

Total $ 7,937 $ 6,389

All of Mohave and a portion of San Onofre and Palo Verde are included in regulatory assets on theconsolidated balance sheets — see Note 11. Mohave ceased operations on December 31, 2005. In December2006, SCE acquired the City of Anaheim’s approximately 3% ownership interest in San Onofre Units 2 and 3.

Note 14. Variable Interest Entities

In December 2003, the FASB issued FIN 46(R). This Interpretation defines a variable interest entity as a legalentity whose equity owners do not have sufficient equity at risk or a controlling financial interest in the entity.Under this Interpretation, the primary beneficiary is the variable interest holder that absorbs a majority ofexpected losses; if no variable interest holder meets this criterion, then it is the variable interest holder thatreceives a majority of the expected residual returns. The primary beneficiary is required to consolidate thevariable interest entity unless specific exceptions or exclusions are met. Edison International uses VIEs toconduct its business as described below.

Description of Use of Variable Interest Entities

EME is a holding company which operates primarily through its subsidiaries and affiliates which are engagedin the business of developing, acquiring, owning or leasing, operating and selling energy and capacity fromindependent power production facilities. EME’s subsidiaries or affiliates have typically been formed to own allor some of the interest in one or more power plants and ancillary facilities, with each plant or group of relatedplants being individually referred to by EME as a project.

EME’s subsidiaries and affiliates have financed the development and construction or acquisition of its projectsby capital contributions from EME and the incurrence of debt or lease obligations by its subsidiaries andaffiliates owning the operating facilities. These project level debt or lease obligations are generally structuredas non-recourse to EME, with several exceptions, including EME’s guarantee of the Powerton and Joliet leasesas part of a refinancing of indebtedness incurred by its project subsidiary to purchase the Illinois Plants. As aresult, these project level debt obligations have structural priority with respect to revenues, cash flows andassets of the project companies over debt obligations incurred by EME as a holding company. Distributions toEME from projects are generally only available after all current debt service or lease obligations at the projectlevel have been paid and are further restricted by contractual restrictions on distributions included in thedocumentation evidencing the project level debt obligations. Assets of EME’s subsidiaries are not available tosatisfy EME’s obligations or the obligations of any of its other subsidiaries. However, unrestricted cash orother assets that are available for distribution may, subject to applicable law and the terms of financingarrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed toEME or to its subsidiary holding companies.

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Edison Capital, through its subsidiaries, has invested in real estate projects. These projects consist primarily ofmulti-family residential properties and located throughout the United States that provide affordable housing forlow and moderate income households. These real estate investments qualify for various tax credits, includingstate and federal low-income housing tax credits, and the federal historic tax credit. With a few exceptions, theprojects are managed and operated by unrelated parties and project debt is non-recourse to Edison Capital.The general partner in these entities is generally the primary beneficiary based on absorbing the majority ofexpected losses.

Categories of Variable Interest Entities

Projects or Entities that are Consolidated

EME has purchased a majority interest in a number of wind projects under joint development agreements withthird-party developers. At December 31, 2008, EME had majority interests in 15 wind projects with a totalgenerating capacity of 630 MW that had minority interests held by others. The projects are located in Iowa,Minnesota, New Mexico, Nebraska and Texas. Minority interest holders have key rights over matters such asbudgets, incurrence of debt, and sale of the project, and in certain cases, receive a higher allocation of incomeand losses after a minimum return is earned by EME. In determining that EME was the primary beneficiary, akey factor was the conclusion that the power sales agreements did not constitute a variable interest since theagreements have a fixed unit price and do not absorb expected losses. As a result, the determination of EMEas the primary beneficiary was based on the allocation of income and losses with EME expected to earn amajority of the expected gains or absorb the majority of the expected losses based on its ownership interest.

Consolidation of QFs —

SCE has variable interests in contracts with certain QFs that contain variable contract pricing provisions basedon the price of natural gas. Four of these contracts are with entities that are partnerships owned in part by arelated party, EME. These four contracts had 20-year terms at inception. The QFs sell electricity to SCE andsteam to nonrelated parties. Under FIN 46(R), Edison International and SCE consolidate these four projects.

In determining that SCE was the primary beneficiary, SCE considered the term of the contract, percentage ofplant capacity, pricing, and other variable interests. SCE performed a quantitative assessment which includedthe analysis of the expected losses and expected residual returns of the entity by using the various estimatedprojected cash flow scenarios associated with the assets and activities of that entity. The quantitative analysisprovided sufficient evidence to determine that SCE was the primary beneficiary absorbing a majority of theentity’s expected losses, receiving a majority of the entity’s expected residual returns, or both.

Project Capacity Termination Date(1) EME Ownership

Kern River 295 MW June 2011 50%Midway-Sunset 225 MW May 2009 50%Sycamore 300 MW December 2007 50%Watson 385 MW December 2007 49%

(1) SCE’s power purchase agreements with Sycamore and Watson expired on December 31, 2007. Discussionson extending the power purchase and steam agreements are underway, but no assurance can be given thatsuch discussions will lead to extensions of these agreements. As of January 1, 2009, these projects sellpower to SCE under agreements with pricing set by the CPUC.

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The following table presents summarized financial information of the SCE VIEs and EME wind projects thathad minority interests held by others that were consolidated at December 31, 2008:


2008

Current assets $ 206Net property, plant and equipment 957Nonutility property 282Other long-term assets 3

Total assets $ 1,448

Current liabilities $ 92Asset retirement obligation 15Long-term obligations net of current maturities 25Deferred revenues 15Other long-term liabilities 18

Total liabilities $ 165

Minority interest(1) $ 268

(1) The minority interest related to SCE’s VIEs takes into consideration EME’s ownership in the Big 4 projects.

Assets serving as collateral for the debt obligations related to the wind projects had a carrying value of$85 million at December 31, 2008 and primarily consist of property, plant and equipment. The consolidatedstatement of income and cash flow includes $4 million of pre-tax income and $30 million of operating cashflow related to variable interest entities that are consolidated.

SCE’s VIE projects do not have any third party debt outstanding. SCE has no investment in, nor obligation toprovide support to, these entities other than its requirement to make contract payments. Any profit or lossgenerated by these entities will not effect SCE’s income statement, except that SCE would be required torecognize losses if these projects have negative equity in the future. These losses, if any, would not affectSCE’s liquidity. Any liabilities of these projects are nonrecourse to SCE.

Consolidation of Wind Development Company —

U.S. Wind Force is a development stage enterprise formed to develop wind projects in West Virginia,Pennsylvania and Maryland. In December 2006, a subsidiary of EME entered into a loan agreement withU.S. Wind Force to fund the redemption of a membership interest held by another party, repayment of loans,distributions to equity holders and future development of wind projects. In accordance with FIN 46(R), EMEdetermined that it is the primary beneficiary because it bears more than 50% of expected losses and,accordingly, EME consolidated U.S. Wind Force beginning December 15, 2006. At December 31, 2008 and2007, the assets consolidated included $3 million and $10 million of intangible assets, respectively, primarilyrelated to project development rights. As project development is completed, the project development rightswill be considered part of property, plant and equipment and depreciated over the estimated useful lives of therespective projects.

During 2008 and 2007, EME recorded a write down of $7 million and $6 million, respectively, of capitalizedcosts related to U.S. Wind Force reflected in “Contract buyout/termination and other” on EdisonInternational’s consolidated statements of income.

Consolidation of Investments in Affordable Housing Projects —

Edison Capital is the primary beneficiary of one real estate project which has $1 million of debt guaranteed bya subsidiary of Edison Capital and nonrecourse debt totaling $10 million at December 31, 2008. Propertyserving as collateral for these loans had a carrying value of $10 million and is classified as nonutility property

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on the December 31, 2008 consolidated balance sheet. Edison Capital is the primary beneficiary in theseentities due to the debt guarantee. Other than the guarantee, the creditors to this project do not have recourseto the general credit of Edison Capital.

Edison Capital is the primary beneficiary of eight real estate investment partnerships that were formed tosyndicate Edison Capitals interests in real estate projects. In these real estate partnerships, Edison Capital hasguaranteed the third party investors yield on their investments. Such guarantees are considered a variableinterest and Edison Capital is considered the primary beneficiary of such investments. At December 31, 2008,the consolidated balance sheet included investments in real estate partnerships and minority interests of$14 million and $12 million, respectively, related to interests of third parties.

Projects that are not Consolidated

EME has a number of investments in power projects that are accounted for under the equity method. Underthe equity method, the project assets and related liabilities are not consolidated on EME’s consolidatedbalance sheet. Rather, EME’s financial statements reflect its investment in each entity and it records only itsproportionate ownership share of net income or loss.

Historically, EME has invested in qualifying facilities, those which produce electrical energy and steam, orother forms of energy, and which meet the requirements set forth in PURPA. Prior to the passage of the EPAct2005, these regulations limited EME’s ownership interest in qualifying facilities to no more than 50% due toEME’s affiliation with SCE, a public utility. For this reason, EME owns a number of domestic energy projectsthrough partnerships in which it has a 50% or less ownership interest.

Entities formed to own these projects are generally structured with a management committee in which EMEexercises significant influence but cannot exercise unilateral control over the operating, funding or constructionactivities of the project entity. Two of these projects have secured long-term debt to finance the assetsconstructed and/or acquired by them. These financings generally are secured by a pledge of the assets of theproject entity, but do not provide for any recourse to EME. Accordingly, a default on a long-term financing ofa project could result in foreclosure on the assets of the project entity resulting in a loss of some or all ofEME’s project investment, but would generally not require EME to contribute additional capital. AtDecember 31, 2008, entities which EME has accounted for under the equity method had indebtedness of$294 million, of which $128 million is proportionate to EME’s ownership interest in these projects.

As of December 31, 2008, EME has five significant variable interests in projects that are not consolidatedconsisting of the Big 4 projects and the Sunrise project. These projects are natural gas-fired facilities with atotal generating capacity of 1,782 MW. An operations and maintenance subsidiary of EME operates the Big 4projects, but EME does not supply the fuel consumed or purchase the power generated by these facilities.EME concluded that the power purchase agreements for these projects represented variable interests in therelated projects and, therefore, it was not the primary beneficiary of these entities. Accordingly, EMEcontinues to account for its variable interests on the equity method. EME’s maximum exposure to loss in thesevariable interest entities is generally limited to its investment in these entities, which totaled $326 million asof December 31, 2008 and is classified as investments in unconsolidated affiliates on EME’s consolidatedbalance sheet.

As of December 31, 2008, EME has a 50% interest in the March Point project. EME has guaranteed, jointlyand severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project powersales agreements to repay capacity payments to the project’s power purchaser in the event that the power salesagreements terminate, March Point Cogeneration Company abandons the project, or the project fails to returnto normal operations within a reasonable time after a complete or partial shutdown, during the term of thepower sales agreements. The obligations under this indemnification agreement as of December 31, 2008, ifpayment were required, would be $56 million, which is EME’s maximum exposure to loss as EME fully

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impaired its equity investment in the project in 2005. EME has not recorded a liability related to theindemnity.

As of December 31, 2008, EME has an 80% interest in the Doga project located in Turkey. EME concludedthat the power sales agreement which transfers ownership interest in the natural gas-fired plant to thegovernment-owned off-taker constituted a variable interest and, consequently, EME was not the primarybeneficiary.

Edison Capital has a number of investments in real estate projects that are accounted for under the equitymethod. Under the equity method, the project assets and related liabilities are not consolidated in EdisonCapitals consolidated balance sheet. Rather, Edison Capital’s financial statements reflect its investment in eachentity and it records only its proportionate ownership share of net income or loss. See Note 19.

Edison Capital’s maximum exposure to loss from affordable housing investments in this category is generallylimited to its net investment balance of $7 million and recapture of tax credits (estimated at $36 million atDecember 31, 2008).

Entities with Unavailable Financial Information

SCE also has seven other contracts with QFs that contain variable pricing provisions based on the price ofnatural gas and are potential VIEs under FIN 46(R). SCE might be considered to be the consolidating entityunder this standard. SCE continues to attempt to obtain information for these projects in order to determinewhether the projects should be consolidated by SCE. These entities are not legally obligated to provide thefinancial information to SCE and have declined to provide any financial information to SCE. Under thegrandfather scope provisions of FIN 46(R), SCE is not required to apply this rule to these entities as long asSCE continues to be unable to obtain this information. The aggregate capacity dedicated to SCE for theseprojects is 263 MW. SCE paid $203 million in 2008 and $180 million in both 2007 and 2006 to theseprojects. These amounts are recoverable in utility customer rates. SCE has no exposure to loss as a result of itsinvolvement with these projects.

Note 15. Preferred and Preference Stock of Utility Not Subject to Mandatory Redemption

SCE’s authorized shares are: $100 cumulative preferred — 12 million shares, $25 cumulative preferred —24 million shares and preference — 50 million shares. There are no dividends in arrears for the preferred stockor preference shares. Shares of SCE’s preferred stock have liquidation and dividend preferences over shares ofSCE’s common stock and preference stock. All cumulative preferred stock is redeemable. When preferredshares are redeemed, the premiums paid, if any, are charged to common equity. No preferred stock not subjectto mandatory redemption was issued or redeemed in the years ended December 31, 2008, 2007 and 2006. InJanuary 2008, SCE repurchased 350,000 shares of 4.08% cumulative preferred stock at a price of $19.50 pershare. SCE retired this preferred stock in January 2008 and recorded a $2 million gain on the cancellation ofreacquired capital stock (reflected in the caption “Common stock” on the consolidated balance sheets). Thereis no sinking fund requirement for redemptions or repurchases of preferred stock.

Shares of SCE’s preference stock rank junior to all of the preferred stock and senior to all common stock.Shares of SCE’s preference stock are not convertible into shares of any other class or series of SCE’s capitalstock or any other security. The preference shares are noncumulative and have a $100 liquidation value. Thereis no sinking fund for the redemption or repurchase of the preference shares.

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SCE’s preferred and preference stock not subject to mandatory redemption is:

Dollars in millions, except per-share amounts December 31, 2008 2007

December 31,

SharesOutstanding

RedemptionPrice

Cumulative preferred stock$25 par value:4.08% Series 650,000 $ 25.50 $ 16 $ 254.24% Series 1,200,000 $ 25.80 30 304.32% Series 1,653,429 $ 28.75 41 414.78% Series 1,296,769 $ 25.80 33 33Preference stockNo par value:5.349% Series A 4,000,000 $ 100.00 400 4006.125% Series B 2,000,000 $ 100.00 200 2006.00% Series C 2,000,000 $ 100.00 200 200

920 929Less issuance costs (13) (14)

Total $ 907 $ 915

The Series A preference stock, issued in 2005, may not be redeemed prior to April 30, 2010. After April 30,2010, SCE may, at its option, redeem the shares in whole or in part and the dividend rate may be adjusted.The Series B preference stock, issued in 2005, may not be redeemed prior to September 30, 2010. AfterSeptember 30, 2010, SCE may, at its option, redeem the shares in whole or in part. The Series C preferencestock, issued in 2006, may not be redeemed prior to January 31, 2011. After January 31, 2011, SCE may, atits option, redeem the shares in whole or in part. No preference stock not subject to mandatory redemptionwas redeemed in the last three years.

At December 31, 2008, accrued dividends related to SCE’s preferred and preference stock not subject tomandatory redemption were $13 million.

Note 16. Business Segments

Edison International’s reportable business segments include its electric utility operation segment (SCE), anonutility power generation segment (EME), and a financial services and other segment (Edison Capital andEMG nonutility subsidiaries). Included in the nonutility power generation segment are the activities of MEHC,the holding company of EME. MEHC’s only substantive activities were its obligations under the seniorsecured notes which were paid in full on June 25, 2007 as discussed in Note 3. MEHC does not have anysubstantive operations. Edison International evaluates performance based on net income.

SCE is a rate-regulated electric utility that supplies electric energy to a 50,000 square-mile area of central,coastal and Southern California. SCE also produces electricity. EME is engaged in the business of developing,acquiring, owning or leasing, operating and selling energy and capacity from electric power generationfacilities. EME also conducts hedging and energy trading activities in power markets open to competition.Edison Capital is a provider of financial services with investments worldwide.

On April 1, 2006, EME received, as a capital contribution from its affiliate, Edison Capital, ownershipinterests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. EMEaccounted for this acquisition at Edison Capital’s historical cost as a transaction between entities undercommon control. As a result of this capital contribution, Edison International’s nonutility power generation

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segment now includes the wind assets and biomass power project previously owned by Edison Capital andincluded in the financial services segment.

The significant accounting policies of the segments are the same as those described in Note 1.

EME’s merchant plants sell electric power generally into the PJM market by participating in PJM’s capacityand energy markets or transact capacity and energy on a bilateral basis. Sales into PJM accounted forapproximately 50%, 51% and 58% of nonutility power generation revenues for the years ended December 31,2008, 2007 and 2006, respectively. Moody’s rates PJM’s senior unsecured debt Aa3. PJM, an ISO with over300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default are shared by all other members basedupon a predetermined formula. At December 31, 2008 and 2007, EME’s account receivable due from PJMwas $61 million and $82 million, respectively.

EME also derived a significant source of its revenues from the sale of energy, capacity and ancillary servicesgenerated at the Illinois Plants to Commonwealth Edison under load requirements services contracts. Salesunder these contracts accounted for 12% and 19% of EME’s consolidated operating revenues for the yearsended December 31, 2008 and 2007, respectively. Commonwealth Edison’s senior unsecured debt rating areBBB- by S&P and Baa3 by Moody’s. At December 31, 2008 and 2007, EME’s account receivable due fromCommonwealth Edison was $23 million and $20 million, respectively.

For the year ended December 31, 2008, a third customer, Constellation Energy Commodities Group, Inc.accounted for 10% of EME’s consolidated operating revenues. Sales to Constellation are primarily generatedfrom EME’s merchant plants and largely consist of energy sales under forward contracts. The contract withConstellation is guaranteed by Constellation Energy Group, Inc., which has a senior unsecured debt rating ofBBB by S&P and Baa3 by Moody’s. At December 31, 2008, EME’s account receivable due fromConstellation was $22 million.

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Reportable Segments Information

The following is information (including the elimination of intercompany transactions) related to EdisonInternational’s reportable segments:

In millionsElectricUtility

NonutilityPower

Generation

FinancialServices

andOther(1)

Parentand

Other(2)Edison

International

2008Operating revenue $ 11,248 $ 2,811 $ 54 $ (1) $ 14,112Depreciation, decommissioning and amortization 1,114 194 4 1 1,313Interest and dividend income 22 36 12 (8) 62Equity in income (loss) from partnerships and

unconsolidated subsidiaries – net — 122 (3) (88) 31Interest expense – net of amounts capitalized 407 279 9 5 700Income tax expense (benefit) – continuing

operations 342 243 29 (18) 596Income (loss) from continuing operations 683 500 60 (28) 1,215Net income (loss) 683(2) 501 60 (29) 1,215Total assets 32,568 9,016 3,089 (58) 44,615Capital expenditures 2,267 552 5 — 2,824

2007Operating revenue $ 10,233 $ 2,580 $ 56 $ (1) $ 12,868Depreciation, decommissioning and amortization 1,011 162 9 (1) 1,181Interest and dividend income 44 98 16 (4) 154Equity in income from partnerships and

unconsolidated subsidiaries – net — 200 28 (149) 79Interest expense – net of amounts capitalized 429 313 10 — 752Income tax expense (benefit) – continuing

operations 337 173 (2) (16) 492Income (loss) from continuing operations 707 342 70 (19) 1,100Net income (loss) 707(2) 340 70 (19) 1,098Total assets 27,477 7,263 3,008 (225) 37,523Capital expenditures 2,286 540 — — 2,826

2006Operating revenue $ 9,859 $ 2,239 $ 70 $ 1 $ 12,169Depreciation, decommissioning and amortization 950 144 13 (2) 1,105Interest and dividend income 58 98 20 (7) 169Equity in income from partnerships and

unconsolidated subsidiaries – net — 186 29 (136) 79Interest expense – net of amounts capitalized 399 393 16 (2) 806Income tax expense (benefit) – continuing

operations 438 145 9 (10) 582Income (loss) from continuing operations 776 247 88 (28) 1,083Net income (loss) 776(2) 344 88 (27) 1,181Total assets 26,110 7,224 3,221 (294) 36,261Capital expenditures 2,226 310 — — 2,536

(1) Includes amounts from EMG nonutility subsidiaries that are not significant as a reportable segment.(2) Includes amounts from Edison International (parent), other Edison International nonutility subsidiaries that

are not significant as a reportable segment, as well as intercompany eliminations.(3) Net income available for common stock.

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The net income (loss) reported for nonutility power generation includes earnings from discontinued operationsof less than one million for 2008, $(2) million for 2007 and $98 million for 2006.

Geographic Information

Edison International’s foreign and domestic revenue and assets information is:


RevenueUnited States $ 14,067 $ 12,816 $ 12,110International 45 52 59

Total $ 14,112 $ 12,868 $ 12,169


AssetsUnited States $ 42,274 $ 35,198International 2,341 2,325Assets of discontinued operations — —

Total $ 44,615 $ 37,523

Note 17. Discontinued Operations

EME previously owned a 220 MW power plant located in the United Kingdom, referred to as the Lakelandproject. An administrative receiver was appointed in 2002 as a result of a default by the project’s counterparty,a subsidiary of TXU Europe Group plc. Following a claim for termination of the power sales agreement, theLakeland project received a settlement of £116 million (approximately $217 million) in 2005. EME wasentitled to receive the remaining amount of the settlement after payment of creditor claims. As creditor claimswere settled, EME received payments of £0.4 million (approximately $1 million) in 2008, £5 million(approximately $10 million) in 2007, and £72 million (approximately $125 million) in 2006. The after-taxincome attributable to the Lakeland project was $1 million, $6 million and $85 million for 2008, 2007 and2006, respectively. Beginning in 2002, EME reported the Lakeland project as discontinued operations andaccounted for its ownership of Lakeland Power on the cost method (earnings are recognized as cash isdistributed from the project).

For all years presented, the results of EME’s international projects, discussed above, have been accounted foras discontinued operations on the consolidated financial statements in accordance with SFAS No. 144.

There was no revenue from discontinued operations in 2008, 2007 or 2006. The pre-tax earnings (loss) fromdiscontinued operations were $6 million in 2008, $3 million in 2007 and $118 million in 2006.

During the fourth quarter of 2006, EME recorded a tax benefit adjustment of $22 million, which resulted fromresolution of a tax uncertainty pertaining to the ownership interest in a foreign project. EME’s payment of$34 million during the second quarter of 2006 related to an indemnity to IPM for matters arising out of theexercise by one of its project partners of a right of first refusal resulted in a $3 million additional lossrecorded in 2006.

There were no assets or liabilities of discontinued operations at December 31, 2008 and 2007.

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Note 18. Acquisitions and Dispositions

Acquisitions

On January 5, 2006, EME completed a transaction with Cielo Wildorado, G.P., LLC and Cielo Capital, L.P. toacquire a 99.9% interest in Wildorado Wind, L.P., which owns a 161 MW wind farm located in the panhandleof northern Texas, referred to as the Wildorado wind project. The acquisition included all development rights,title and interest held by Cielo in the Wildorado wind project, except for a small minority stake in the projectretained by Cielo. The total purchase price was $29 million. This project started construction in April 2006and commenced commercial operation during April 2007. The acquisition was accounted for utilizing thepurchase method. The fair value of the Wildorado wind project was equal to the purchase price and as aresult, the total purchase price was allocated to property, plant and equipment on Edison International’sconsolidated balance sheet.

Dispositions

On March 7, 2006, EME completed the sale of a 25% ownership interest in the San Juan Mesa wind projectto Citi Renewable Investments I LLC, a wholly owned subsidiary of Citicorp North America, Inc. Proceedsfrom the sale were $43 million. EME recorded a pre-tax gain on the sale of approximately $4 million duringthe first quarter of 2006.

Note 19. Investments in Leveraged Leases, Partnerships and Unconsolidated Subsidiaries

Leveraged Leases

Edison Capital is the lessor in various power generation, electric transmission and distribution, transportationand telecommunication leases with terms of 24 to 38 years. Each of Edison Capital’s leveraged leasetransactions was completed and accounted for in accordance with SFAS No. 13, “Accounting for Leases.” Alloperating, maintenance, insurance and decommissioning costs are the responsibility of the lessees. Theacquisition cost of these facilities was $6.9 billion at both December 31, 2008 and 2007. The equityinvestment in these facilities is generally 20% of the cost to acquire the facilities. The balance of theacquisition costs was funded by nonrecourse debt secured by first liens on the leased property. The lenders donot have recourse to Edison Capital in the event of loan default. See discussion of federal and state tax issuesrelated to LILO/SILO leases in the “Cross-Border Lease Transactions” disclosure in Note 4.

The net income from leveraged leases is:


Income from leveraged leases $ 51 $ 50 $ 67Tax effect of pre-tax income:

Current 11 26 41Deferred (30) (43) (66)

Total tax (expense) benefit (19) (17) (25)

Net income from leveraged leases $ 32 $ 33 $ 42

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The net investment in leveraged leases is:


Rentals receivable – net $ 3,227 $ 3,297Estimated residual value 42 42Unearned income (802) (866)

Investment in leveraged leases 2,467 2,473Deferred income taxes (2,313) (2,316)

Net investment in leveraged leases $ 154 $ 157

Rental receivables are net of principal and interest on nonrecourse debt, credit reserves and the current portionof rentals receivable. Credit reserves were $6 million and $5 million at December 31, 2008 and 2007,respectively. The current portion of rentals receivable was $32 million and $74 million at December 31, 2008and 2007, respectively.

First Energy exercised an early buyout right under the terms of an existing lease agreement with EdisonCapital related to Unit No. 2 of the Beaver Valley Nuclear Power Plant. The termination date of the leaseunder the early buyout option was June 1, 2008. Proceeds from the sale were $72 million. Edison Capitalrecorded a pre-tax gain of $41 million ($23 million after tax) during the second quarter of 2008 which isreflected in “Contract buyout/termination and other” on Edison International’s consolidated statements ofincome.

Partnerships and Unconsolidated Subsidiaries

Edison International and its nonutility subsidiaries have equity interests primarily in energy projects, oil andgas and real estate investment partnerships.

The difference between the carrying value of these equity investments and the underlying equity in the netassets was $12 million at December 31, 2008. The difference is being amortized over the life of the energyprojects.

Summarized financial information of these investments is:


Revenue $ 557 $ 581 $ 707Expenses 534 552 676

Net income $ 23 $ 29 $ 31


Current assets $ 313 $ 305Other assets 2,508 3,187

Total assets $ 2,821 $ 3,492

Current liabilities $ 255 $ 190Other liabilities 1,667 1,890Equity 899 1,412

Total liabilities and equity $ 2,821 $ 3,492

The undistributed earnings of equity method investments were $2 million in 2008 and $7 million in 2007.

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Note 20. Quarterly Financial Data (Unaudited)

In millions, except per-share amounts Total Fourth Third Second First2008

Operating revenue $ 14,112 $ 3,228 $ 4,295 $ 3,477 $ 3,113Operating income 2,563 466 965 506 628Income from continuing operations 1,215 217 433 262 304Income (loss) from discontinued operations – net — — 6 (1) (5)Net income 1,215 217 439 261 299Basic earnings (loss) per share:

Continuing operations 3.69 0.66 1.31 0.79 0.92Discontinued operations — — 0.02 — (0.01)Total 3.69 0.66 1.33 0.79 0.91

Diluted earnings (loss) per share:Continuing operations 3.68 0.66 1.31 0.79 0.92Discontinued operations — — 0.02 — (0.01)Total 3.68 0.66 1.33 0.79 0.91

Dividends declared per share 1.225 0.310 0.305 0.305 0.305Common stock prices:

High 55.70 40.94 52.35 54.17 55.70Low 26.73 26.73 37.86 49.14 46.81Close 32.12 32.12 39.90 51.38 49.02

In millions, except per-share amounts Total Fourth Third Second First2007

Operating revenue $ 12,868 $ 3,144 $ 3,900 $ 3,019 $ 2,805Operating income 2,509 481 899 501 627Income from continuing operations 1,100 214 465 91(1) 330Income (loss) from discontinued operations – net (2) (3) (4) 2 3Net income 1,098 211 461 93 333Basic earnings (loss) per share:

Continuing operations 3.34 0.65 1.41 0.28 1.00Discontinued operations (0.01) (0.01) (0.01) 0.01 0.01Total 3.33 0.64 1.40 0.29 1.01

Diluted earnings (loss) per share:Continuing operations 3.32 0.65 1.40 0.28 1.00Discontinued operations (0.01) (0.01) (0.01) — 0.01Total 3.31 0.64 1.39 0.28 1.01

Dividends declared per share 1.175 0.305 0.29 0.29 0.29Common stock prices:

High 60.26 58.55 59.57 60.26 51.00Low 42.76 53.14 50.64 49.13 42.76Close 53.37 53.37 55.45 56.12 49.13

As a result of rounding, the total of the four quarters does not always equal the amount for the year.(1) Reflects a $241 million pre-tax ($148 million after tax) loss on early extinguishment of debt.

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Selected Financial Data: 2004 – 2008 Edison International

Dollars in millions, except per-shareamounts 2008 2007 2006 2005 2004

Edison International and SubsidiariesOperating revenue $ 14,112 $ 12,868 $ 12,169 $ 11,417 $ 10,242Operating expenses $ 11,549 $ 10,359 $ 9,680 $ 9,102 $ 9,147Income from continuing operations $ 1,215 $ 1,100 $ 1,083 $ 1,108 $ 226Net income $ 1,215 $ 1,098 $ 1,181 $ 1,137 $ 916Weighted-average shares of common stock

outstanding (in millions) 326 326 326 326 326Basic earnings (loss) per share:

Continuing operations $ 3.69 $ 3.34 $ 3.28 $ 3.38 $ 0.69Discontinued operations $ — $ (0.01) $ 0.30 $ 0.09 $ 2.12Total $ 3.69 $ 3.33 $ 3.58 $ 3.47 $ 2.81

Diluted earnings per share $ 3.68 $ 3.31 $ 3.57 $ 3.45 $ 2.77Dividends declared per share $ 1.225 $ 1.175 $ 1.10 $ 1.02 $ 0.85Book value per share at year-end $ 29.21 $ 25.92 $ 23.66 $ 20.30 $ 18.56Market value per share at year-end $ 32.12 $ 53.37 $ 45.48 $ 43.61 $ 32.03Rate of return on common equity 13.7% 13.6% 16.5% 18.1% 17.1%Price/earnings ratio 8.7 16.0 12.7 12.6 11.4Ratio of earnings to fixed charges 2.73 2.45 2.48 2.49 1.11Total assets $ 44,615 $ 37,523 $ 36,261 $ 34,791 $ 33,269Long-term debt $ 10,950 $ 9,016 $ 9,101 $ 8,833 $ 9,678Preferred and preference stock of utility not

subject to mandatory redemption $ 907 $ 915 $ 915 $ 729 $ 129Common shareholders’ equity $ 9,517 $ 8,444 $ 7,709 $ 6,615 $ 6,049Preferred stock subject to mandatory

redemption $ — $ — $ — $ — $ 139Retained earnings $ 7,078 $ 6,311 $ 5,551 $ 4,798 $ 4,078

Southern California Edison CompanyOperating revenue $ 11,248 $ 10,233 $ 9,859 $ 9,065 $ 8,491Net income available for common stock $ 683 $ 707 $ 776 $ 725 $ 915Basic earnings per Edison International

common share $ 2.10 $ 2.17 $ 2.38 $ 2.22 $ 2.81Total assets $ 32,568 $ 27,477 $ 26,110 $ 24,703 $ 23,290Rate of return on common equity 10.7% 12.0% 15.0% 15.3% 21.0%

Edison Mission EnergyRevenue $ 2,811 $ 2,580 $ 2,239 $ 2,265 $ 1,653Income (loss) from continuing operations $ 500 $ 416 $ 316 $ 414 $ (560)Net income (loss) $ 501 $ 414 $ 414 $ 442 $ 130Total assets $ 9,080 $ 7,272 $ 7,235 $ 6,655 $ 7,081Rate of return on common equity 21.7% 18.4% 18.4% 24.2% 7.0%

Edison CapitalRevenue $ 58 $ 56 $ 73 $ 77 $ 87Net income $ 58 $ 69 $ 89 $ 81 $ 52Total assets $ 3,033 $ 2,977 $ 3,199 $ 3,376 $ 3,279Rate of return on common equity 14.2% 15.6% 9.6% 12.3% 8.1%

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The selected financial data was derived from Edison International’s audited financial statements and isqualified in its entirety by the more detailed information and financial statements, including notes to thesefinancial statements, included in this annual report. Prior to 2007, the above table included MEHC. BecauseMEHC paid off its long-term debt in 2007, it no longer files with the SEC. Therefore, beginning with 2007,the above table includes Edison Mission Energy data. Amounts presented in this table have been revised toreflect Edison Capital’s capital contribution to MEHC. See Note 16 for further discussion. During 2004, EMEsold 11 international projects.

Amounts presented in this table have been revised to reflect continuing operations unless stated otherwise. SeeNote 17, Discontinued Operations, for further discussion.

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Edison International Leading the Way in ElectricitySM

Edison International, through its subsidiaries, is a generator and distributor of electric power and an investor ininfrastructure and energy assets, including renewable energy. Headquartered in Rosemead, California, EdisonInternational is the parent company of Southern California Edison, one of the nation’s largest electric utilities,and Edison Mission Group, a competitive power generation business and parent company to Edison MissionEnergy and Edison Capital.

$ 0

$100

$200

$300

$400

$500

$600

Comparison of Five-Year

Cumulative Total Return

EDISON INTERNATIONALS&P 500 INDEXPHILADELPHIA UTILITY INDEX

12-0812-0712-0612-0512-0412-03

12/03 12/04 12/05 12/06 12/07 12/08

Edison International 100 152 212 227 273 169

S & P 500 Index 100 111 116 135 142 90

Philadelphia Utility Index 100 126 149 179 213 155

Note: Assumes $100 invested on December 31, 2003 in stock or index including reinvestment of dividends. Performance of thePhiladelphia Utility Index is regularly reviewed by management and the Board of Directors in understanding Edison International’srelative performance and is used in conjunction with elements of the company’s incentive compensation program.


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